(1) Assumes a ratio of 6 Mcf of natural gas per barrel of oil.
The following table sets forth summary information with respect to historical and pro forma combined oil, natural gas and natural gas liquids production for the year ended March 31, 2014 for Earthstone and for the year ended December 31, 2013 for Oak Valley. The Earthstone and Oak Valley oil, natural gas and natural gas liquids production data presented below was derived from independent engineering reports of each company.
|
|
Earthstone
Historical
Twelve Months Ended
|
|
|
Oak Valley
Historical
Twelve Months Ended
|
|
|
Eagle Ford Acquisition
|
|
|
Earthstone Pro Forma Combined
|
|
Oil (MBbls)
|
|
|
174 |
|
|
|
163 |
|
|
|
171 |
|
|
|
508 |
|
Natural Gas (MMcf)
|
|
|
190 |
|
|
|
2,635 |
|
|
|
95 |
|
|
|
2,920 |
|
NGL (MBbls)
|
|
|
– |
|
|
|
134 |
|
|
|
– |
|
|
|
134 |
|
Total (MBOE) (1)
|
|
|
206 |
|
|
|
737 |
|
|
|
187 |
|
|
|
1,130 |
|
(1) Assumes a ratio of 6 Mcf of natural gas per barrel of oil.
COMPARATIVE PER SHARE INFORMATION
The following table sets forth certain historical net income (loss) per share and book value per share information of Earthstone on an unaudited pro forma stand alone and a combined basis after giving effect to the exchange under the purchase method of accounting.
The unaudited pro forma condensed combined per share information does not purport to represent what the results of operations or financial position of the combined company would actually have been had the exchange actually occurred at the beginning of the period shown or to project the combined company’s results of operations or financial position for any future period or date. Such pro forma information is derived from, and should be read in conjunction with, the unaudited pro forma condensed combined financial information and accompanying notes included in this proxy statement as described under “Unaudited Pro Forma Condensed Combined Financial Information of Earthstone Energy, Inc.” beginning on page F-1.
The historical per share information is derived from, and should be read in conjunction with, the financial statements of Earthstone included elsewhere in this proxy statement. Earthstone did not declare any cash dividends related to its equity ownership or common stock during the period presented.
Earthstone Historical Per Common Share Data (as of and for the twelve months ended March 31, 2014):
|
|
|
|
Basic
|
|
$ |
2.27 |
|
Diluted
|
|
$ |
2.27 |
|
Book value (a)
|
|
$ |
14.11 |
|
Pro Forma Combined Per Common Share Data: (b)
|
|
|
|
|
Basic (b)
|
|
$ |
(0.09 |
) |
Diluted (b)
|
|
$ |
(0.09 |
) |
Book value (c)
|
|
$ |
26.71 |
|
(a)
|
Computed by dividing stockholders’ equity by the number of weighted average outstanding shares of Earthstone common stock at the end of such period.
|
(b)
|
Based on the pro forma net income for Earthstone for the twelve months ended March 31, 2014 and for Oak Valley for the twelve months ended December 31, 2013, which gives effect to the exchange under the purchase method of accounting as if it occurred on January 1, 2013.
|
(c)
|
Computed by dividing stockholders’ equity by the number of weighted average outstanding shares of Earthstone common stock at the end of such period, adjusted to include the estimated number of shares of Earthstone common stock to be issued in the exchange plus the dilutive effect of shares of restricted stock at the end of such period.
|
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This proxy statement contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to Earthstone’s and Oak Valley’s financial condition, results of operations and businesses and the expected impact of the proposed combination. Words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “could,” “would,” “will,” “may,” “can,” “continue,” “potential,” “should,” and the negative of these terms or other comparable terminology often identify forward-looking statements. Statements in this proxy statement that are not historical facts are hereby identified as “forward-looking statements” for the purpose of the safe harbor provided by Section 21E of the Exchange Act, and Section 27A of the Securities
Act of 1933, as amended (the “Securities Act”). These forward-looking statements are found at various places throughout this proxy statement. Forward-looking statements relate to, among other things:
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completion of the exchange and other transactions contemplated in the exchange agreement;
|
●
|
strategies for the combined company after the exchange;
|
●
|
future financial position, including anticipated liquidity;
|
●
|
the ability to satisfy obligations from cash generated from operations;
|
●
|
amounts and nature of future capital expenditures;
|
●
|
acquisitions and other business opportunities;
|
●
|
operating costs and other expenses, including asset retirement obligation expenses;
|
●
|
wells expected to be drilled, other anticipated exploration and development efforts and associated expenses;
|
●
|
estimates of proved oil and natural gas reserves and depletion rates;
|
●
|
the ability to meet additional acreage, seismic and/or drilling cost requirements; and
|
●
|
other estimates and assumptions used in accounting policies.
|
These statements, wherever they occur in this proxy statement, are necessarily estimates reflecting the best judgment of the respective management of the parties and involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Many of the important factors that will determine these results are beyond Earthstone’s or Oak Valley’s ability to control or predict. These forward-looking statements should, therefore, be considered in light of various important factors, including those set forth in this proxy statement. In addition to the risk factors identified elsewhere, important factors that could cause actual results to differ materially from estimates or projections contained in the forward-looking statements include, without limitation:
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|
factors that affect the timing or ability to complete the exchange and transactions contemplated herein;
|
●
|
the risk that the businesses of Earthstone and Oak Valley will not be integrated successfully;
|
●
|
the risk that cost savings and any other synergies from these transactions may not be fully realized or may take longer to realize than expected;
|
●
|
disruption from these transactions, making it more difficult to maintain relationships with lenders, other counterparties, or employees;
|
●
|
competition and its effects on pricing, spending, third-party relationships and revenues;
|
●
|
the failure of the combined company to successfully execute its business plans, gain access to additional financing, acquire additional oil and gas properties, and the cost of capital;
|
●
|
loss of senior management or technical personnel;
|
●
|
oil and natural gas prices and production costs;
|
●
|
the ability to replace oil and natural gas reserves, including changes in reserve estimates resulting from unexpected oil and gas prices, production rates, tax rates and production costs;
|
●
|
the ability to remain in compliance with the financial covenants related to any credit facility, which may be affected by events beyond Earthstone’s control, including market prices for the company’s oil and gas. Any future inability to comply with these covenants could adversely affect liquidity by reducing available borrowings under any credit facility;
|
●
|
exploitation, development, production and exploration results, including mechanical failures;
|
●
|
the estimated costs of asset retirement obligations;
|
●
|
the potential unavailability of drilling rigs and other field equipment and services;
|
●
|
the existence of unanticipated liabilities relating to existing properties or those acquired in the future, including environmental liabilities;
|
●
|
factors affecting the nature and timing of capital expenditures, including the availability of service contractors and equipment;
|
●
|
the willingness and ability of third parties to honor their contractual commitments;
|
●
|
the nature, extent and duration of workovers;
|
●
|
the impact and costs related to compliance with or changes in laws governing oil and gas operations, including hydraulic fracturing;
|
●
|
acquisitions and other business opportunities (or the lack thereof) that may be pursued by the combined company;
|
●
|
economic, market or business conditions, including any change in interest rates or inflation;
|
●
|
the availability of capital and financing;
|
●
|
risk factors consistent with comparable companies within the oil and gas industry, especially companies with similar market capitalization and/or employee census; and
|
Furthermore, forward-looking statements are made based on Earthstone management’s current assessment available at the time. Subsequently obtained information concerning the merits of any property, as well as changes in estimated exploration and development costs and ownership interest, may result in revisions to Earthstone management’s expectations and intentions and, thus, Earthstone may alter its plans regarding any exploration and development activities.
You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this proxy statement. Earthstone does not undertake any obligation to update publicly or release any revisions to these forward-looking statements to reflect events or circumstances after the date of this proxy statement or to reflect the occurrence of unanticipated events, except as required by law.
In addition to the other information included in this proxy statement, including the matters addressed under the caption “Cautionary Statement Concerning Forward-Looking Statements” beginning on page 17, you should carefully read and consider the following factors in evaluating the proposals to be voted on at the special meeting and in determining whether to vote for approval of the matters to be considered at the meeting.
Risk Factors Relating to the Exchange
The failure to integrate Oak Valley successfully on a timely basis could reduce Earthstone’s profitability and adversely affect its stock price.
Earthstone expects to realize increased liquidity and diversification of its asset base from the exchange. Realization of these benefits will depend in part upon how and when the businesses of Earthstone and Oak Valley are integrated. If Earthstone, with its new management consisting primarily of Oak Valley management, and the reconstituted Earthstone Board, are not successful in this integration, Earthstone’s financial results could be adversely impacted. Integration of operations will require substantial attention of new Earthstone management and consequently could divert attention away from the development of new business and further development of oil and gas properties. If Earthstone and Oak Valley cannot integrate their businesses successfully, they may fail to realize the benefits they expect to realize from the exchange. The challenges involved in this integration include the following:
●
|
retaining key employees and maintaining employee morale;
|
●
|
minimizing the diversions of management and employees away from ongoing business activities and development of new business activities;
|
●
|
addressing differences in the business cultures, processes and systems of Earthstone and Oak Valley; and
|
●
|
potential unknown liabilities and unforeseen increased expenses or delays associated with the exchange.
|
Failure to complete the exchange could negatively impact the stock price and the future business and financial results of Earthstone.
There is no assurance that the conditions to the completion of the exchange agreement will be satisfied. If the exchange is not completed, Earthstone will be subject to several risks, including the following:
●
|
The current market price of Earthstone common stock may reflect a market assumption that the exchange will occur, and a failure to complete the exchange could result in negative market perception and a decline in the market price of Earthstone common stock;
|
●
|
Certain costs relating to the exchange agreement, such as legal, accounting and financial advisory fees associated with the delivery of a fairness opinion which have already been incurred by Earthstone or are payable by Earthstone whether or not the exchange is completed;
|
●
|
Earthstone may be required to pay Oak Valley a termination fee of $1,000,000 if the exchange agreement is terminated under certain circumstances and Earthstone enters into or completes an alternative transaction;
|
●
|
There will likely be substantial disruption to the business of Earthstone and a distraction of its management and employees from day-to-day operations because matters related to the exchange agreement (including integration planning) may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to Earthstone; and
|
●
|
Earthstone would continue to face the risks that it currently faces as an independent company, including limited capital and limited human resources.
|
In addition, Earthstone would not realize any of the expected benefits of having completed the exchange. If the exchange is not completed, these risks may materialize and materially adversely affect Earthstone’s business, financial results, financial condition and stock price.
After the exchange, Oak Valley will own 84% of the Earthstone common stock and will hold six of the seven seats on the Earthstone Board, thereby controlling all corporate governance matters.
After completion of the exchange, Oak Valley will own 84% of the Earthstone common stock, and its representatives will hold six of the seven seats on the Earthstone Board and all of the executive management positions other than that held by Mr. Singleton. There is no assurance that Mr. Singleton will be re-nominated following the expiration of his current term. As a result, Oak Valley will be able to determine the outcome of all corporate actions of Earthstone requiring stockholder approval, including the ability to elect all of the directors, amendments to the certificate of incorporation, mergers or other actions, and the ability to formulate corporate policy.
The concentration of ownership in Oak Valley could have the effect of delaying or preventing a change of control of Earthstone.
Since Oak Valley representatives will control the Earthstone Board, Oak Valley will be able to determine the timing and price of any sale of Earthstone. An offer to purchase the stock or assets of Earthstone may not be in the time frame or price range considered acceptable to Oak Valley, even though the offer might be beneficial to other stockholders of Earthstone.
Earthstone may waive one or more of the conditions to the exchange without re-soliciting stockholders.
Each of the conditions in the exchange agreement to Earthstone’s obligations to complete the exchange may be waived, in whole or in part by agreement of Earthstone and Oak Valley if the condition is a condition to Earthstone’s and Oak Valley’s obligations to complete the exchange, or by the party for which such condition is a condition of its obligation to complete the exchange. The Earthstone Board may evaluate the materiality of any such waiver to determine whether amendment of this proxy statement and re-solicitation of proxies is necessary. If the Board were to determine that a waiver would materially alter the relative values of the consideration to be given or received in the exchange, the Earthstone Board would likely re-solicit proxies. In the event that any such waiver is not determined to be significant enough to require re-solicitation of stockholders, Earthstone will have the discretion to complete the exchange without seeking
further stockholder approval.
The exchange agreement limits Earthstone’s ability to pursue alternatives to the exchange.
The exchange agreement contains provisions that could adversely impact competing proposals to acquire Earthstone. These provisions include generally prohibiting Earthstone from soliciting any acquisition proposal or offer for a competing transaction and the requirement that Earthstone pay a termination fee of $1.0 million in cash if the exchange agreement is terminated in specified circumstances in connection with an alternative transaction. In addition, even if the Board of Directors of Earthstone determines that a competing proposal to acquire Earthstone is superior, Earthstone may not exercise its right to terminate the exchange agreement unless it notifies Oak Valley of its intention to do so and gives Oak Valley at least three business days to propose revisions to the terms of the exchange agreement or to make another proposal in response to the competing
proposal. See “The Exchange Agreement – Additional Agreements” beginning on page 73.
Earthstone agreed to these provisions as a condition to Oak Valley’s willingness to enter into the exchange agreement. These provisions, however, might discourage a third party that might have an interest in acquiring all or a significant part of Earthstone from considering or proposing an acquisition of Earthstone, even if that party were prepared to pay consideration with a higher value than the current proposed exchange consideration. Further, the termination fee may result in a potential competing acquiror proposing to pay a lower per share price to acquire Earthstone than it might otherwise have proposed to pay.
While the Oak Valley management team has been successful in other business combination transactions, there can be no assurance that its prior success will be repeated in the combination with Earthstone.
After the exchange, Earthstone’s management and board will be controlled by Oak Valley. When the Earthstone Board was considering whether to enter into the business combination with Oak Valley, one of the positive factors considered was the success Oak Valley’s management and technical team has had in past business combinations. However, Earthstone stockholders should not assume or conclude that Earthstone’s stock price, float or trading volume will increase as a result of the transactions contemplated by the exchange or as result of future activities or by decisions made by the new board of directors and management team, or that an exit strategy by Oak Valley will benefit Earthstone stockholders.
Risk Factors Associated with the Combined Company
Earthstone is not required to have a majority of independent directors.
Oak Valley’s ownership of 84% of Earthstone’s common stock will make Earthstone a “controlled company” under the corporate governance rules of the NYSE MKT. As a controlled company, Earthstone will not be required to comply with the NYSE MKT requirements that independent directors constitute a majority of the board of directors, nominating committee or compensation committee. However, as a “smaller reporting company,” as such term is defined under the Exchange Act, and in accordance with applicable rules and regulations of the NYSE MKT, Earthstone is required to have an audit committee consisting of two independent members. Directors representing Oak Valley may not have the same interests as Earthstone’s other stockholders, and Earthstone’s other stockholders will not have the same corporate governance protections they currently have or that they would have if Earthstone were not a controlled company. Earthstone
will have greater risks of conflicts of interest without those safeguards.
The combined company will be dependent upon the services of its Chief Executive Officer, other officers, and its technical personnel.
The combined company will be dependent upon a limited number of personnel, including Frank A. Lodzinski, who will serve as a Director, Chief Executive Officer and President of the combined company, Ray Singleton, current Chief Executive Officer and President of Earthstone, who will serve as Executive Vice President, Northern Region of the combined company, and other senior officers and key employees. One of the significant components of this transaction for Earthstone stockholders is that the Oak Valley management team, particularly Mr. Lodzinski, has been successful in the past in achieving positive results in business combinations similar to the one with Earthstone, and Oak Valley’s management expertise was of significant importance to Earthstone in this combination.
Failure to retain the services of these persons, or to replace them with personnel with similar skills in the event of their departure or termination, may have a material adverse effect on operations of the combined company. No employment agreements with any officers of Oak Valley or Earthstone currently exist, but the combined company may consider such agreements in the future.
There is not significant liquidity in the Earthstone common stock, and the exchange will not increase that liquidity.
Prior to the exchange, Earthstone’s public float consists of approximately 1,280,000 shares of common stock, and its average daily trading volume for a recent three-month period was only 10,000 shares. Therefore, it may be difficult for Earthstone stockholders to sell or buy a significant number of shares. A lack of liquidity typically makes the price of a stock more volatile, as trades of even a small number of shares can significantly affect the stock price. Although Earthstone will issue a large number of shares in the exchange, such shares will be treated initially as restricted shares, which will not be registered under the Securities Act and thus may not be traded in the public markets until such time as a registration statement is filed with the SEC. In addition, some market participants may be reluctant to buy Earthstone stock after the exchange because of the control of Earthstone by Oak Valley and because of the
potential future disposition of Oak Valley’s large number of shares. As a result, your ability to sell your Earthstone common stock in open market transactions has not been enhanced by the exchange and may have been limited.
The increase in Earthstone’s authorized shares of common and preferred stock provides the opportunity for future dilutive issuances.
The proposed amendment to the certificate of incorporation will increase the authorized common stock from 6.4 million shares to 100 million shares, and will increase the authorized preferred stock from 600,000 shares to 20 million shares. The shares can be used as consideration in acquisitions and provides significant opportunity for equity financing. In addition, the Earthstone Board can issue series of preferred stock having certain rights superior to Earthstone’s common stock without stockholder approval. The availability of a significant number of shares makes it possible for large issuances to occur, and these issuances could have the effect of diluting existing stockholders.
Risk Factors Associated with the Oil and Gas Business
The combined company must successfully replace production and acquire or develop additional oil and gas reserves.
Oil and gas reserves are a depleting asset and must be replaced to sustain operations and to achieve asset growth. Future production of oil and gas will depend upon cost-effective operations, development of the assets and acquiring or finding additional reserves.
Intense competition in the oil and gas exploration and production industry could adversely affect the ability of the combined company to acquire desirable oil and gas properties.
The oil and gas industry is highly competitive, and the combined company’s small size puts it at a disadvantage in competing for resources.
The oil and gas industry is highly competitive. The combined company will compete with major integrated and larger independent oil and gas companies for the acquisition of desirable oil and gas properties and leases, for the equipment and services required to develop and operate properties, and in the marketing of oil and gas to end-users. Many competitors have financial and other resources that are substantially greater than those of the combined company, which will make any acquisition of acreage or producing properties at economic prices difficult. In addition, many larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production, such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels and the application of government regulations. Significant competition also exists in attracting and retaining technical
personnel, including geologists, geophysicists, engineers, landmen and other specialists, as well as financial and administrative personnel.
A failure to complete successful acquisitions after the exchange would limit the combined company’s growth.
The combined company’s future success is highly dependent on its ability to find, acquire or develop economically recoverable oil and gas reserves. Without continued successful acquisition, exploration or development projects, the combined company’s current oil and gas reserves will decline due to continued production activities. Acquiring additional oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise, is an important component of the combined company’s strategy. If the combined company identifies an appropriate acquisition candidate, management may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. The combined company’s limited access to financial resources compared to larger, better capitalized companies may limit its ability to make future acquisitions. If the combined
company is unable to complete suitable acquisitions, it will be more difficult to replace and increase its reserves, and an inability to replace its reserves would have a material adverse effect on the combined company’s financial condition and results of operations.
Acquisitions involve a number of risks, including the risk that the combined company will discover unanticipated liabilities or other problems associated with the acquired business or property.
In assessing potential acquisitions, the combined company will consider information available in the public domain and information provided by the seller. In the event publicly available data is limited, then, by necessity, it may rely to a large extent on information that may only be available from the seller, particularly with respect to drilling and completion costs and practices, geological, geophysical and petrophysical data, detailed production data on existing wells, if any, and other technical and cost data not available in the public domain. Accordingly, the review and evaluation of the business or property to be acquired may not uncover all existing or relevant data, obligations or actual or contingent liabilities that could adversely impact the business or property to be acquired and, hence, could adversely affect the combined company as a result of the acquisition. These issues may be material and
could include, among other things, unexpected environmental problems, title defects or other liabilities. If the combined company acquires properties on an “as-is” basis, it will have limited or no remedies against the seller with respect to these types of problems.
The success of any acquisition that the combined company completes will depend on a variety of factors, including its ability to accurately assess the reserves associated with the acquired properties, future oil and natural gas prices and operating costs, potential environmental and other liabilities and other factors. These assessments are often inexact and subjective. As a result, the combined company may not recover the purchase price of a property from the sale of production from the property or recognize an acceptable return from such sales. In addition, the combined company may face greater risks to the extent it acquires properties in areas outside of areas in which it currently operates because it may be less familiar with operating, regulatory and other issues specific to those areas.
The combined company’s ability to achieve the benefits that it expects from an acquisition will also depend on its ability to efficiently integrate the acquired operations. Management may be required to dedicate significant time and effort to the integration process, which could divert its attention from other business concerns. The challenges involved in the integration process may include retaining key employees and maintaining key employee morale, addressing differences in business cultures, processes and systems and developing internal expertise regarding the acquired properties.
The combined company may be faced with shortages of personnel and equipment, thereby adversely affecting operations and financial results.
Operations and financial results of the combined company may be adversely impacted due to difficulties in attracting and retaining qualified and experienced personnel. Additional personnel are likely to be required in connection with any expansion plans, and the domestic oil and gas industry is currently experiencing significant shortages of qualified personnel in all areas of operations. Similarly, expansion plans of the combined company will require access to services and oil field equipment, both of which are currently in short supply.
Volatile oil and natural gas prices could adversely affect the combined company’s financial condition and results of operations.
The combined company’s success will be largely dependent on oil and natural gas prices, which are volatile. While the combined company intends to hedge a portion of its production as a protective measure, any substantial or extended decline in the price of oil and natural gas will have a negative impact on the combined company’s business operations and future revenues. Moreover, oil and natural gas prices depend on factors that will be outside the combined company’s control, such as:
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|
economic and energy infrastructure disruptions caused by actual or threatened acts of war, or terrorist activities;
|
●
|
weather conditions, including energy infrastructure disruptions resulting from those conditions;
|
●
|
changes in the global and domestic oil supply, demand and inventories;
|
●
|
changes in domestic natural gas supply, demand and inventories;
|
●
|
the price and quantity of foreign imports of oil;
|
●
|
the price and availability of liquefied natural gas imports;
|
●
|
political conditions in or affecting other oil-producing countries;
|
●
|
general economic conditions in the United States and worldwide;
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●
|
the level of worldwide oil and natural gas exploration and production activity;
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●
|
technological advances affecting energy consumption; and
|
●
|
the price and availability of alternative fuels.
|
Lower oil and natural gas prices not only may decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that can be produced economically. Lower prices will also negatively impact estimates of proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect the combined company’s financial condition, results of operations, liquidity or ability to finance operations and planned capital expenditures.
Industry changes may adversely affect various financial measurements and negatively affect the market price of Earthstone common stock.
Although the parties to the exchange agreement believe the exchange will allow the combined company to have greater access to financial resources and therefore accelerate its growth, unforeseen industry changes and increased costs could potentially have an adverse effect on the returns on invested capital and earnings per share. Future events and conditions could cause any such changes to be significant, including, among other things, adverse changes in:
●
|
commodity prices for oil, natural gas and liquid natural gas;
|
●
|
economically recoverable reserves;
|
●
|
capital expenditure obligations; and
|
The combined company may incur substantial losses and be subject to substantial liability claims as a result of its oil and natural gas operations and drilling operations.
Oil and natural gas exploration, drilling and production activities are subject to numerous operating risks, including the possibility of:
●
|
unanticipated, abnormally pressured formations;
|
●
|
mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
|
●
|
blowouts, fires and explosions;
|
●
|
personal injuries and death;
|
●
|
uninsured or underinsured losses; and
|
●
|
environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination.
|
Any of these operating hazards could cause damage to properties, serious injuries, fatalities, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages, which could expose the combined company to liabilities. Although the parties to the exchange agreement believe they are adequately insured for replacement costs of their wells and associated equipment, the payment of any of these liabilities could reduce the funds available for exploration, development, and acquisition, or could result in a loss of the combined company’s properties. The combined company does not intend to carry business interruption insurance.
The insurance market in general and the energy insurance market in particular have experienced cost increases. It is possible that the combined company will replace the amount and types of its insurance because of high insurance premiums. If the combined company incurs substantial liabilities and the damages are not fully covered by insurance or are in excess of policy limits, then the combined company’s business, results of operations and financial condition would likely be materially adversely affected.
The nature of the combined company’s business and assets will expose it to significant compliance costs and liabilities.
The combined company’s operations involving the exploration and production of liquid hydrocarbons, including crude oil, will be subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. The combined company’s operations will also be subject to laws and regulations relating to protection of the environment, operational safety, and related employee health and safety matters. Laws and regulations applicable to the combined company include those relating to the following:
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|
problems in delivery of the combined company’s oil and natural gas to market;
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●
|
drilling bonds and other financial responsibility requirements;
|
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|
emissions into the air;
|
●
|
unitization and pooling of properties;
|
●
|
habitat and endangered species protection, reclamation and remediation;
|
●
|
containment and disposal of hazardous substances, oil field waste and other waste materials;
|
●
|
use of saltwater injection wells, which affects the disposal of saltwater from the combined company’s wells;
|
●
|
prevention of oil spills;
|
●
|
operational reporting; and
|
●
|
taxation and royalties.
|
Compliance with all of these laws and regulations will continue to represent a significant cost of doing business. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; the imposition of investigatory and remedial liabilities; the issuance of injunctions that may restrict, inhibit or prohibit the combined company’s operations; or claims of damages to property or persons.
Some environmental laws and regulations impose strict liability. Strict liability means that in some situations, the combined company could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties the combined company acquired or of other third parties. Similarly, some environmental laws and regulations impose joint and several liability, meaning that the combined company could be held responsible for more than its share of a particular reclamation or other obligation, and potentially the entire obligation, where other parties were involved in the activity giving rise to the liability. In addition, the combined company may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly,
the combined company’s plugging and abandonment obligations are and will continue to be substantial and may be more than its estimates. It is not possible for the combined company to estimate reliably the amount and timing of all future expenditures related to environmental matters, but they will be material. Environmental risks are generally not fully insurable.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the combined company’s production of oil and gas and lower returns on its capital investments.
Bills have been introduced in the U.S. Congress and in various state legislatures to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the federal Safe Drinking Water Act (“SDWA”) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act (“EPCRA”) or other authority. Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale and tight sand formations. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. The combined company will engage third parties to provide hydraulic fracturing or other well stimulation services to it for
many of the wells that it drills and operates. Sponsors of such bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies, surface waters, and other natural resources, and threaten health and safety. In addition, the Environmental Protection Agency (“EPA”) has announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health, and the EPA issued a draft study plan on hydraulic fracturing. Certain states and localities have also considered or imposed reporting and other operational obligations relating to the use of hydraulic fracturing techniques.
Certain states, including Texas, where Oak Valley conducts operations, have adopted, and other states are considering the adoption of, regulations that impose new or more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. Such efforts have resulted in the imposition of bans on hydraulic fracturing. Some local jurisdictions, including Dallas, Texas, have adopted regulations restricting hydraulic fracturing. The proliferation of regulations may limit the combined company’s ability to conduct hydraulic fracturing, which is an essential component of its current operations in the Eagle Ford and Bakken areas.
Additional legislation or regulation could make it easier for parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process adversely affect groundwater. There has also been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated in Texas and other states implicating hydraulic fracturing practices.
Legislation, regulation, litigation and enforcement actions at the federal, state or local level that restrict hydraulic fracturing services could limit the availability and raise the cost of such services, delay completion of new wells and production of the combined company’s oil and gas, lower its return on capital expenditures and have a material adverse impact on its business, financial condition, results of operations and cash flows and quantities of oil and gas reserves that may be economically produced.
Any change to government regulation or administrative practices may have a negative impact on the combined company’s ability to operate and the combined company’s profitability.
The business of oil and gas exploration and development is subject to substantial regulation under federal, state and local laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of, oil and gas and related products and other matters. Amendments to current laws and regulations governing operations and activities of oil and gas exploration and development operations could have a material adverse impact on the combined company’s business. In addition, there can be no assurance that income tax laws, royalty regulations and government incentive programs related to the combined company’s oil and gas properties and the oil and gas industry generally will not be changed in a manner which may adversely affect the combined company’s progress or cause delays, an inability to explore and develop or the abandonment of these interests.
Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of the combined company’s activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect the combined company’s exploration and development activities.
Revisions of oil and gas reserve estimates could adversely affect the trading prices of Earthstone common stock. Oil and gas reserves and the standardized measure of cash flows represent estimates, which may vary materially over time due to many factors.
The market prices of Earthstone common stock may be subject to significant decreases due to decreases in estimated reserves and their estimated future cash flows. Estimated reserves may be subject to downward revision based upon future production, results of future development, prevailing oil and gas prices, prevailing operating and development costs and other factors. There are numerous uncertainties and uncontrollable factors inherent in estimating quantities of oil and gas reserves, projecting future rates of production, and timing of development expenditures.
In addition, the estimates of future net cash flows from proved reserves and the present value of proved reserves are based upon various assumptions about prices and costs and future production levels that may prove to be incorrect over time. Any significant variance from the assumptions could result in material differences in the actual quantity of reserves and amount of estimated future net cash flows from estimated oil and gas reserves.
Reserves, as referred to in this proxy statement, are calculated in accordance with SEC regulations and should not be construed as the current market value of the estimated oil and gas attributable to the combined company’s properties. The timing of actual future net cash flows from proved reserves, and thus their actual value, will be affected by the timing of production, actual prices received and the incurrence of expenses in connection with both extraction costs and development costs. In addition, the 10% discount factor, which is required by the SEC to be used for reporting purposes, may not necessarily reflect the actual time value of money.
Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. While reservoir engineering techniques are based on accepted industry practices, the determination of reserve quantities also includes subjective judgments related to the future recovery of underground accumulations of oil and natural gas. The accuracy of any estimate is a function of the quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions,
such as future operating costs, severance and excise taxes, development costs, remediation costs and the assumed effects of regulations by governmental agencies, all of which may in fact vary considerably from actual results. Other variables, notably oil and gas prices, which are determined using the average first day of the month price for each of the preceding 12 months, may vary considerably from actual prices received in the future. For these reasons, estimates of the economically recoverable reserves attributable to any property or any group of properties, classifications of such reserves based upon risk of recovery and estimates of the expected future net cash flows may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances may be material.
Hedging activities may prevent realizing the benefits of oil or gas price increases.
While Earthstone has not historically engaged in hedging transactions, it will assume Oak Valley’s hedges in effect at the time of closing of the exchange. The combined company intends to enter into hedging transactions in the future in an attempt to reduce its sensitivity to oil and gas price volatility, resulting in increased predictability of its cash flows. Such hedging transactions include fixed price swaps, price collars, puts and other derivatives. In these hedging transactions, the combined company may fix the price, a floor or a range, on a portion of its production over a predetermined period of time. In addition, the combined company expects to enter into a credit agreement that may require that a portion of oil and gas production be hedged. There are numerous risks associated with hedging activities, including the risk that reserves are not produced at rates equivalent to the hedged position. In
that case, the combined company would be required to satisfy its obligation under hedging contracts on potentially unfavorable terms without the benefit of offsetting cash flow from sales of its production. In addition, there is also the risk that the production and transportation cost assumptions used in determining an acceptable hedge could be substantially different from the actual costs. Further, by hedging to a fixed price or a range with a ceiling, revenues will be limited if actual prices rise above the hedge prices. Also, the counter party to the hedge party may become unable or unwilling to perform its obligations under hedging contracts, and the combined company could incur a material adverse financial effect if there is any significant non-performance. As a result, hedging transactions
could be uneconomic and the combined company could incur losses.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect the financial condition and results of operations of the combined company.
The combined company’s success will depend on the results of its exploitation, exploration, development and production activities. Oil and natural gas exploration and production activities are subject to numerous risks beyond a company’s control, including the risk that drilling will not result in commercially viable oil or natural gas production. Decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including:
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shortages of or delays in obtaining equipment and qualified personnel;
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pressure or irregularities in geological formations;
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equipment failures or accidents;
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adverse weather conditions;
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reductions in oil and natural gas prices;
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delays imposed by or resulting from compliance with regulatory requirements.
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The combined company’s business involves significant operating risks that could adversely affect its production and could be expensive to remedy. The combined company may not have insurance in amounts sufficient to cover all of the risks that it may face.
The combined company’s operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including well blowouts; fires; mechanical and operational problems that affect completion of wells and production; formations with abnormal or depleted pressures; and unpredictable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution, including groundwater contamination and releases of contaminants into the environment. In addition to potential increased costs or lost production, these hazards could cause fatalities, serious injuries, or third-party property damage for which the combined company could be held responsible.
As is common in the oil and gas industry, the combined company may not maintain insurance in amounts that cover all of the losses to which it may be subject, and the insurance it has may not continue to be available on acceptable terms. Moreover, the combined company does not intend to carry business interruption insurance, and some risks it faces may not be insurable. Although the parties to the exchange agreement believe they have appropriately considered the risks and are adequately insured for replacement costs of wells and equipment and environmental risks, the occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on the combined company’s financial condition and liquidity.
The energy insurance market has experienced cost increases. It is possible that the combined company will replace the amount and types of its insurance, or increase retentions or deductibles because of high insurance premiums. If the combined company incurs substantial liabilities and the damages are not fully covered by insurance or are in excess of policy limits, then the combined company’s business, results of operations and financial condition would likely be materially adversely affected.
The marketability of the combined company’s production is dependent upon gathering systems, transportation facilities and processing facilities that it does not own or control. If these facilities or systems are unavailable, the combined company’s operations can be interrupted and its revenues reduced.
The marketability of the combined company’s oil and natural gas production is dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation and processing facilities owned by third parties. In general, the combined company will not control these facilities, and its access to them may be limited or denied due to circumstances beyond its control. A significant disruption in the availability of these facilities could adversely impact the combined company’s ability to deliver to market the oil and natural gas it produces and thereby cause a significant interruption in its operations. In some cases, the combined company’s ability to deliver to market its oil and natural gas is dependent upon coordination among third parties that own transportation and processing facilities it uses, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt
its operations. These are risks for which the combined company generally will not maintain insurance.
Use of debt financing may adversely affect the combined company’s strategy.
After the exchange, management may choose to use debt to fund a portion of its future operating and acquisition activities. Any temporary or sustained inability to service or repay debt will materially adversely affect the combined company’s ability to access the financing market and to pursue its operating strategies, as well as impair its ability to respond to adverse economic changes in oil and gas markets and the economy in general. Upon consummation of the exchange, the combined company expects to use a portion of its existing cash to repay its outstanding debt.
Non-operated properties will be controlled by third parties that do not allow the combined company to proceed with planned explorations and expenditures. Activities on operated properties could also be limited or subject to penalties.
While the combined company intends to operate the majority of its properties in the future, it is not currently the operator of many of its existing properties and, therefore, may not be able to influence production operations or further development activities. At present, the combined company will operate wells comprising approximately 52% of its total proved oil and gas reserve quantities and 56% of its proved reserves. Joint ownership is customary in the oil and gas industry and is generally conducted under the terms of a Joint Operating Agreement (“JOA”), where one of the working interest owners is designated as the “operator” of the property. For non-operated properties, subject to the specific terms and conditions of the applicable JOA, if the combined company disagrees with the decision of a majority of working interest owners, it may be required, among other things, to postpone the proposed activity or
decline to participate. If the combined company declines to participate, it might be forced to relinquish its interest through “in-or-out” elections or may be subject to certain non-consent penalties, as provided in a JOA. In-or-out elections may require a joint owner to participate or forever relinquish its position, typically only in specific wells or drilling units, although such relinquished positions could be of a larger scope. Non-consent penalties typically allow participating working interest owners to recover from the proceeds of production, if any, an amount equal to 200% to 500% of the non-participating working interest owner’s share of the cost of such operations. Further, even for properties operated by the combined company, there may be instances where decisions related to drilling, completion and operating cannot be made in its sole discretion. In such instances, the combined company could be limited in its development operations and subject to
penalties as specified above if it chooses not to participate in operations proposed by a majority of working interest owners.
Because the combined company cannot control activities on properties it does not operate, it cannot control the timing of those projects. If the combined company is unable to fund required capital expenditures with respect to non-operated properties, its interests in those properties may be reduced or forfeited.
The combined company’s ability to exercise influence over operations and costs for those properties it does not operate is limited. Its dependence on the operator and other working interest owners for these projects and its limited ability to influence operations and associated costs could prevent the realization of its targeted returns on capital with respect to exploration, exploitation, development or acquisition activities. The success and timing of exploration, exploitation and development activities on properties operated by others depend upon a number of factors that may be outside the combined company’s control, including:
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the timing and amount of capital expenditures;
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the operator’s expertise and financial resources;
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the approval of other participants in drilling wells; and
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the selection of technology.
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Where it is not the majority owner or operator of a particular oil and natural gas project, the combined company may have no control over the timing or amount of capital expenditures associated with the project. If the combined company is not willing or able to fund required capital expenditures relating to a project when required by the majority owner or operator, the combined company’s interests in the project may be reduced or forfeited. Also, the combined company could be responsible for plugging and abandonment and other liabilities in excess of its proportionate interest in the property.
Because the combined company cannot control the timing and accuracy of financial information regarding the results of operations on properties it does not operate, its ability to timely and accurately report its results of operations and financial position may be adversely affected.
For properties it does not operate, the combined company is dependent on the operator of such property for financial information regarding the results of operations. Any delay in receipt of such information or inaccuracies in calculating and reporting such information by the operator of the property would adversely affect the combined company’s ability to timely and accurately report its results of operations and financial condition.
If oil and gas prices decrease or exploration efforts are unsuccessful, the combined company may be required to write-down the capitalized cost of individual oil and gas properties.
A write-down of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if the combined company has substantial downward adjustments to its estimated proved oil and gas reserves, if operating costs or development costs increase over prior estimates, or if exploratory drilling is unsuccessful. A write-down could adversely affect the trading price of Earthstone common stock.
The combined company will use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.
The capitalized costs of the oil and gas properties of the combined company, on a field-by-field basis, may exceed the estimated future net cash flows of that field. If so, the combined company will record impairment charges to reduce the capitalized costs of each such field to its estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce earnings and stockholders’ equity.
The combined company will periodically assess its properties for impairment based on future estimates of proved and non-proved reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if the combined company experiences increases in the price of oil or gas, or both, or increases in the amount of its estimated proved reserves.
MARKET PRICE AND DIVIDEND INFORMATION
Market Price Data and Dividend Information
Earthstone’s common stock trades on the NYSE MKT under the symbol “ESTE.” The following table sets forth for the period indicated the low and high sales prices for Earthstone’s common stock as reported by the NYSE MKT. These sales reflect prices between dealers and do not include retail markups, markdowns or commissions.
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2014:
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$ |
37.21 |
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$ |
27.50 |
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2nd Quarter
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$ |
35.00 |
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$ |
18.97 |
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1st Quarter
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$ |
22.70 |
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$ |
17.48 |
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2013:
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4th Quarter
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$ |
19.21 |
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$ |
16.06 |
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3rd Quarter
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$ |
17.20 |
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$ |
12.70 |
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2nd Quarter
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$ |
16.49 |
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$ |
13.26 |
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1st Quarter
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$ |
18.50 |
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$ |
15.74 |
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2012:
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4th Quarter
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$ |
18.11 |
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$ |
14.74 |
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3rd Quarter
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$ |
16.25 |
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$ |
13.44 |
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2nd Quarter
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$ |
22.75 |
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$ |
15.54 |
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1st Quarter
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$ |
26.70 |
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$ |
15.47 |
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There has never been a public market for the Oak Valley membership interests.
The following table provides the lowest and highest sales prices for Earthstone’s common stock as reported by the NYSE MKT as of May 14, 2014, the last full trading day preceding public announcement that Earthstone and Oak Valley had entered into the exchange agreement, and on September 15, 2014, the last full trading day for which such prices were available at the time of this proxy statement. Because Oak Valley membership interests are not traded on any established market, no equivalent market price data is available for Oak Valley.
Date |
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Highest
Sales Price
Per Share
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Lowest
Sales Price
Per Share
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$ |
22.00 |
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$ |
21.70 |
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$ |
28.25 |
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$ |
27.50 |
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Number of Stockholders
As of September 15, 2014, there were approximately 1,842 holders of record of Earthstone’s common stock. As of September 15, 2014, there were 87 holders of Oak Valley’s membership interests.
Earthstone has never declared or paid a cash dividend on its common stock. The future payment of dividends, if any, on the common stock is within the discretion of the Board of Directors and will depend upon earnings, capital requirements, financial condition and other relevant factors. Earthstone’s current borrowing agreement restricts, and Earthstone expects that the revolving credit agreement it will enter into at the closing of the exchange will restrict, the ability of the combined company to pay dividends.
Dividend Policy After the Exchange
Any future dividends on Earthstone’s common stock will be at the discretion of the board of directors and will be dependent upon Earthstone’s earnings and financial condition, receipt of any required lender’s consent and other factors. The reconstituted board of directors has no plans to pay any dividends in the foreseeable future but rather will retain earnings of Earthstone, if any, to increase its oil and gas activities.
Transfer Agent and Registrar
Earthstone’s present transfer agent is Direct Transfer LLC.
THE EARTHSTONE SPECIAL MEETING
The special meeting of the holders of Earthstone common stock will take place on ____________, 2014 at ______ a.m., Denver Time, at the offices of Davis Graham & Stubbs LLP, 1550 Seventeenth Street, Suite 500, Denver, Colorado 80202.
At the special meeting, holders of Earthstone shares will be asked to consider and vote upon four proposals. The first proposal will be to approve the issuance of up to 9,124,452 shares of common stock pursuant to the exchange agreement. The second proposal will be to approve an amendment to the certificate of incorporation of Earthstone to increase the total number of authorized shares of stock from 7,000,000 shares of stock, consisting of 6,400,000 shares of common stock, $0.001 par value per share, and 600,000 shares of preferred stock, $0.001 par value per share, to 120,000,000 shares of stock, consisting of 100,000,000 shares of common stock, $0.001 par value per share, and 20,000,000 shares of preferred stock, $0.001 par value per share. The third proposal will be to approve and adopt the 2014 Plan, which, among other things, authorizes
the reservation of 750,000 shares of common stock. If the exchange is not completed for any reason, including for lack of requisite stockholder approval, Earthstone will not implement the proposal to adopt the 2014 Plan or the proposal to amend the certificate of incorporation to increase the authorized shares of stock. The fourth proposal will be to approve, by a non-binding advisory vote, the Severance Plan, which provides that under certain circumstances one of Earthstone’s named executive officers may be entitled to receive compensation in connection with the exchange.
Holders of Earthstone shares may also be asked to consider and vote upon such other matters as may properly come before the special meeting, or any adjournment or postponement of the special meeting. As of the mailing date of this proxy statement, the Earthstone Board knows of no other matter to be presented at the special meeting. If, however, other matters incident to the conduct of the special meeting are properly brought before the special meeting, or any adjournment or postponement of the special meeting, the persons named in the proxy will vote the proxies in accordance with their best judgment with respect to those matters.
Recommendation of the Earthstone Board
The Earthstone Board has carefully reviewed and considered the terms and conditions of each of the matters to be considered at the special meeting. Based on its review, Earthstone’s Board of Directors has unanimously approved (i) the proposed issuance of the common stock pursuant to the exchange agreement, (ii) the amendment to the certificate of incorporation, (iii) the 2014 Plan, and (iv) the Severance Plan, and declared that these proposals are advisable and fair to, and in the best interests of, Earthstone and its stockholders. Earthstone’s Board unanimously recommends that you vote (i) “FOR” the proposal to issue shares of common stock pursuant to the exchange agreement, (ii) “FOR” the proposal to approve the amendment to the certificate
of incorporation, (iii) “FOR” the approval and adoption of the 2014 Plan, and (iv) “FOR” the approval, on a non-binding advisory basis, of the Severance Plan.
Record Date, Outstanding Shares and Voting Rights
Each holder of record of Earthstone common stock at the close of business on ___________, 2014, the record date, is entitled to notice of and to vote at the special meeting. Each such stockholder is entitled to cast one vote for each Earthstone share on each matter properly submitted for the vote of stockholders at the special meeting. As of the record date, there were ________ shares of Earthstone common stock outstanding and entitled to vote at the special meeting.
Quorum and Vote Required; Abstentions and Broker Non-Votes
A quorum of Earthstone stockholders is necessary to hold the special meeting. The required quorum for the transaction of business at the special meeting is the presence, in person or by proxy, of holders of a majority of the outstanding shares of Earthstone common stock entitled to vote at the special meeting. Stockholders are counted as present at the special meeting if they are present in person or have authorized a proxy. The presence of holders of _________ shares of common stock is a quorum. Shares of Earthstone common stock held by stockholders who are not present in person or by proxy will not be counted towards a quorum.
All Earthstone shares represented at the special meeting in person or by proxy, including abstentions but excluding “broker non-votes,” will be counted as present at the special meeting for the purpose of determining whether a quorum is present at the special meeting. Abstentions occur when a stockholder attends a meeting in person or by proxy but abstains from voting. Broker non-votes occur when a nominee holding Earthstone shares for a beneficial owner returns a properly executed proxy but has not received voting instructions from the beneficial owner and such nominee does not possess or does not choose to exercise discretionary authority with respect to such shares. Brokers are not allowed to exercise their voting discretion with respect to the approval of matters which FINRA determines to be “non-routine,” without specific instructions from the beneficial owner. All of the matters to be voted on at the meeting
are considered “non-routine.” Accordingly, if your broker holds your Earthstone shares in “street name,” your broker will vote your shares only if you provide instructions on how to vote by filling out the voter instruction form sent to you by your broker with this proxy statement.
The proposals regarding the issuance of Earthstone shares pursuant to the exchange agreement and the 2014 Plan, in accordance with NYSE MKT listing requirements, as well as the Severance Plan (by a non-binding advisory vote) will be approved if the holders of a majority of Earthstone shares cast vote in favor of such proposals in person or by proxy at the special meeting, assuming a quorum, consisting of the holders of a majority of the shares entitled to vote, is present in person or by proxy. The proposal to amend the certificate of incorporation will be approved if it receives the affirmative vote of a majority of Earthstone’s outstanding shares of common stock. If the exchange is not completed for any reason, including for lack of requisite stockholder approval, Earthstone will not implement the proposal to adopt the 2014 Plan or the
proposal to increase its authorized shares of stock.
Abstentions will have the same effect as voting “AGAINST” the proposals at the special meeting. Because the proposal to amend Earthstone’s certificate of incorporation requires the approval of a majority of the outstanding common stock of Earthstone, broker non-votes and shares of Earthstone common stock held by stockholders who are not present in person or by proxy will have the same effect as voting “AGAINST” that proposal. However, broker non-votes and shares of Earthstone common stock held by stockholders who are not present in person or by proxy will have no effect on (i) the proposal to issue Earthstone shares pursuant to the exchange agreement, (ii) the proposal to approve and adopt the Earthstone 2014 Long-Term Incentive Plan, or (iii) the non-binding advisory proposal to approve the Severance Plan.
Voting by Earthstone Directors and Executive Officers
As of the record date, the directors and executive officers of Earthstone beneficially owned and were entitled to vote ___________ common shares, which represent approximately ___% of the Earthstone shares outstanding on that date. Mr. Singleton, who owns 453,360 common shares constituting approximately 26% of the outstanding shares of Earthstone, has entered into a voting agreement, attached to this proxy statement as Annex B, under which he agreed to vote in favor of the exchange, the exchange agreement and the other transactions contemplated by the exchange agreement, unless the exchange agreement is terminated in accordance with its terms. The remaining directors and executive officers of Earthstone are expected to vote FOR all the proposals submitted by this proxy statement.
Adjournment and Postponement
Adjournments and postponements of the special meeting may be made for the purpose of, among other things, soliciting additional proxies. The special meeting may be adjourned by the vote of a majority of the Earthstone shares present in person or represented by proxy at the special meeting, even if less than a quorum.
All Earthstone shares entitled to vote and represented by properly executed proxies received prior to the special meeting, and not revoked, will be voted at the special meeting in accordance with the instructions indicated on the proxy card accompanying this proxy statement. If no direction is given and the proxy is validly executed, the stock represented by the proxy will be voted in favor of the proposals. The persons authorized under the proxies will vote upon any other business that may properly come before the special meeting according to their best judgment to the same extent as the person delivering the proxy would be entitled to vote. Earthstone does not anticipate that any other matters will be raised at the special meeting.
If you are a registered holder, there are two additional ways to vote your proxy:
Vote by telephone — call toll free ______________.
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Vote your proxy 24 hours a day, 7 days a week, until 11:59 p.m. _______ Time on _________, 2014.
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Please have your proxy card and the last four digits of your Social Security Number or Tax Identification Number available. Follow the simple instructions the voice provides you.
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Vote by the Internet — http://www.________________
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Use the Internet to vote your proxy 24 hours a day, 7 days a week, until 11:59 p.m. _______ Time on _________, 2014.
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Please have your proxy card and the last four digits of your Social Security Number or Tax Identification Number available. Follow the simple instructions to obtain your records and create an electronic ballot.
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Your telephone or Internet vote authorizes the named proxies to vote your shares in the same manner as if you had marked, signed and returned your proxy card. The law of Delaware, where Earthstone is incorporated, allows a proxy to be sent electronically, so long as it includes or is accompanied by information that lets the inspector of elections know that it has been authorized by the stockholder.
If your shares are held in “street name” or through another nominee, your broker or nominee may provide the option of voting through the Internet or by telephone instead of by mail. Please check the voting instruction card provided by your broker or nominee to see which options are available and the procedures to be followed.
You can revoke your proxy at any time before the vote is taken at the special meeting. If you have not voted through your broker, you may revoke your proxy by:
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submitting written notice of revocation to the Corporate Secretary of Earthstone prior to the voting of the proxy, which is dated later than the proxy;
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submitting a properly executed later-dated proxy by mail, telephone or the Internet; or
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voting in person at the special meeting; however, simply attending the special meeting without voting will not revoke an earlier proxy.
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Voting by Attending the Special Meeting
Holders of record of Earthstone shares and their authorized proxies may also vote their shares in person at the special meeting. If a stockholder attends the special meeting, he or she may submit his or her vote in person, and any previous votes or proxies authorized by the stockholder by mail will be superseded by the vote that such stockholder casts at the special meeting.
If a stockholder has authorized a proxy by returning a proxy card, such stockholder may change his or her vote before his or her proxy has been exercised by:
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giving written notice of revocation no later than the commencement of the special meeting to Earthstone’s Corporate Secretary, Ray Singleton, at Earthstone Energy, Inc., 633 Seventeenth Street, Suite 2320, Denver, Colorado 80202;
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delivering no later than the commencement of the special meeting a properly executed, later-dated proxy;
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voting in person at the special meeting; or
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if your shares are held in “street name,” you should follow the instructions of your broker or nominee regarding revocation of proxies. If your broker or nominee allows you to vote by telephone or the Internet, you may be able to change your vote by voting again by telephone or the Internet.
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Solicitation of Proxies; Expenses
Earthstone is soliciting proxies for the special meeting from its stockholders and will bear all costs and expenses incurred in connection with soliciting proxies, including preparation, assembly, printing and mailing of this proxy statement and the accompanying proxy cards. Copies of solicitation materials will be furnished to banks, brokerage houses, fiduciaries and custodians holding in their names shares of Earthstone common stock beneficially owned by others to forward to such beneficial owners. Proxies may be solicited on Earthstone’s behalf by its directors, officers or employees in person, by telephone, facsimile or by other electronic means. In accordance with SEC regulations, Earthstone will reimburse brokerage firms and other custodians, nominees and fiduciaries for their expenses incurred in mailing proxies and proxy materials and soliciting proxies from the beneficial owners of its common stock.
No Exchange of Certificates
There will be no change in stock certificates for Earthstone in connection with the exchange, and Earthstone stockholders will keep their existing certificate(s).
If you need assistance in completing your proxy card, have questions regarding the special meeting, its proposed matters, or how to submit your proxy or want additional copies of this proxy statement or the enclosed proxy card, please contact Ray Singleton, the Corporate Secretary of Earthstone, at (303) 296-3076.
PROPOSAL 1 – APPROVAL OF THE ISSUANCE
OF SHARES OF COMMON STOCK IN THE EXCHANGE
Earthstone common stock is traded on the NYSE MKT under the symbol “ESTE.” Applicable NYSE MKT rules require that the Earthstone stockholders approve the stock issuance pursuant to the exchange agreement. As of the record date, Earthstone had _________ shares of common stock issued and outstanding. In the exchange, a total of 9,124,452 shares of Earthstone common stock will be issued to Oak Valley. Earthstone is therefore seeking the approval of its stockholders for the issuance of these additional shares of common stock.
Following these transactions, the existing stockholders of Earthstone will hold 16% of the combined company.
The immediately following sections of this proxy statement describe the material aspects of the exchange and other transactions contemplated in the exchange agreement. You should read carefully this entire document and the other documents to which Earthstone refers, including the exchange agreement attached as Annex A, as well as the other attached annexes to this proxy statement, for a more complete understanding of the proposed transactions.
THE EARTHSTONE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS THAT THE
EARTHSTONE STOCKHOLDERS VOTE “FOR” APPROVAL
OF THE ISSUANCE OF THE SHARES OF COMMON STOCK TO OAK VALLEY,
AS PROVIDED IN THE EXCHANGE AGREEMENT.
This discussion of the exchange is qualified in its entirety by reference to the exchange agreement, which is attached to this proxy statement as Annex A. Stockholders are encouraged to read the exchange agreement carefully and in its entirety, as it is the definitive legal document that governs the exchange.
Background of the Exchange
The Earthstone Board of Directors continuously reviews the company’s strategic goals and alternatives, performance and prospects as part of its ongoing evaluation of its business in an effort to enhance shareholder value. From time to time, this review has included consideration of a wide range of possible strategic alternatives. The summary below provides the background of the proposed exchange.
Ray Singleton, Earthstone’s President and Chief Executive Officer, has been informally acquainted with Frank A. Lodzinski, Oak Valley’s President and Chief Executive Officer, for nearly a decade. In early March 2013, Mr. Singleton received an unsolicited telephone call from a senior coverage officer in STRH’s oil and gas exploration and production industry group with whom Mr. Singleton was acquainted, who as part of ordinary course efforts to develop a relationship with Earthstone suggested that Mr. Singleton contact Mr. Lodzinski to learn about Oak Valley’s business strategy. At the time, Oak Valley had been in existence for only a few months and possessed limited producing assets but had significant financial resources. Although STRH had not previously advised Oak Valley
in any transaction, STRH was generally familiar with Oak Valley and its senior management team. Mr. Singleton spoke briefly to Mr. Lodzinski by telephone in late March 2013. Interested in speaking further to Mr. Lodzinski and hearing more about Oak Valley’s plans and business strategy, including the possibility of a business combination transaction, Mr. Singleton asked STRH to organize an in-person meeting in Houston, Texas during one of Mr. Singleton’s routine trips to Texas. A mutual confidentiality agreement was signed by both parties on April 18, 2013.
On April 22, 2013, Mr. Singleton met with senior management of Oak Valley in its Houston, Texas office. Oak Valley was represented at the meeting by Frank A. Lodzinski, Robert J. Anderson, its Executive Vice President – Corporate Development and Engineering, and Neil K. Cohen, its Vice President – Finance, as well as certain other members of its management team. Mr. Singleton was the only representative from Earthstone present. Representatives from STRH also attended this meeting. During the meeting, Oak Valley introduced its senior management team, described its assets, and presented an overview of its corporate strategy. Mr. Lodzinski described his previous success in using private equity financing as an initial step to building a public company, with the goal of profitable expansion and increasing
shareholder value and trading liquidity over time, while concurrently positioning the company for a significant monetization event, should any such opportunities be favorable. He noted that most recently he undertook a similar transaction with GeoResources, Inc., which, over a five-year period, he and his team grew significantly and profitably, with increased shareholder value and trading liquidity. GeoResources was ultimately sold to Halcón Resources Corporation in 2012. Mr. Lodzinski also noted that nearly all of his management team had been with him through some or all of his prior companies, including GeoResources. The meeting was focused on preliminary information sharing, but Oak Valley did provide a preliminary indication of how it conceived that a potential transaction could be structured and noted that it anticipated that Earthstone stockholders would hold approximately 10% of
the combined company, based on the estimated relative values of the Earthstone and Oak Valley assets, including the anticipated cash contribution to be made by Oak Valley.
On Wednesday, April 24, 2013, the Board of Directors of Earthstone held a special meeting to discuss Mr. Singleton’s meeting with Oak Valley. Also present at that meeting was a representative from Earthstone’s legal advisor, Davis Graham & Stubbs LLP (“DGS”). At that meeting, Mr. Singleton relayed the information that he received from Oak Valley. The Board thoroughly discussed the potential opportunity, including how to value appropriately the assets of Earthstone and Oak Valley, as well as the potential cash that would be contributed by Oak Valley, which was expected to include Oak Valley’s existing cash on hand as well as capital that was committed by Oak Valley’s members. The Board concluded that the unique opportunity presented by Oak Valley should be investigated more thoroughly. The Board also discussed whether to engage a financial advisor to assist it in
evaluating the Oak Valley proposal and deferred any decision on that matter to a subsequent meeting.
The Board held a subsequent meeting on May 6, 2013. The purpose of that meeting was to consider whether to engage STRH as a financial advisor in connection with the evaluation of the proposed Oak Valley transaction. A representative from DGS also attended the meeting telephonically. Representatives from STRH attended the meeting telephonically and gave a presentation regarding their capabilities, industry experience and prior transactions. Following the presentation, members of the Board and STRH had further discussion regarding the appropriate metrics that should be evaluated in order to determine the relative values of Earthstone and Oak Valley. Following STRH’s departure from the call, the Board discussed STRH’s qualifications and other potential investment banking candidates with which the Board was familiar. The Board also discussed the proposed terms of STRH’s engagement,
as proposed in a draft engagement letter that was circulated by STRH prior to the meeting. Favorably impressed by STRH’s qualifications and the proposed terms of its engagement, the Board authorized Mr. Singleton to negotiate the terms of its engagement for the sole purpose of evaluating the Oak Valley transaction.
Following the May 6, 2013 meeting, Mr. Singleton, together with Earthstone’s legal advisors at DGS, negotiated the terms of STRH’s engagement. On June 13, 2013, the Board held another meeting at which the engagement with STRH was formally approved. Earthstone and STRH then executed the engagement letter, which was dated as of May 22, 2013.
During the month of June 2013, Earthstone delivered to Oak Valley its March 31, 2013 reserve report, and Oak Valley delivered to Earthstone its December 31, 2012 reserve report. The Oak Valley reserve report did not include the properties in Gonzales and Fayette Counties, Texas that Oak Valley subsequently acquired in July 2013 and August 2013 for an aggregate purchase price of approximately $87 million. Occasional discussions took place among Earthstone and Oak Valley personnel throughout the months of July, August and September as each party continued to analyze the other party’s reserve report. Earthstone also engaged its reserve engineer, Ryder Scott, to review the Oak Valley reserve report. As with prior discussions, the parties’ discussions focused primarily on understanding the other party’s assets and did not address
or consider the terms of any potential transaction.
On October 22, 2013, Mr. Cohen, Oak Valley’s Vice President – Finance, sent an e-mail to Mr. Singleton indicating a desire to enter into formal discussions regarding a business combination. The e-mail included a letter from Mr. Lodzinski to Mr. Singleton outlining the terms of Oak Valley’s proposal. Oak Valley proposed a business combination whereby all of the assets and cash of Oak Valley would be contributed or otherwise transferred to Earthstone, and Earthstone would issue approximately 14.6 million shares of its common stock to Oak Valley, resulting in an ownership split of 89.4% for Oak Valley and 10.6% for the existing Earthstone stockholders. For purposes of determining the proposed ownership split, the parties used a comparable risked net asset value analysis, including (i) the risk-adjusted PV-10 value associated with Oak Valley’s latest reserve report as of October
1, 2013 and Earthstone’s March 31, 2013 reserve report, rolled forward to October 1, 2013, (ii) the risk-adjusted value associated with each company’s non-proved acreage, and (iii) each company’s net financial assets. As is customary in the oil and gas industry, the proposal applied different risk weighting to the PV-10 values ascribed to different categories of assets to reflect the risk associated with realizing those values. In its initial proposal, Oak Valley applied a risk weighting to Earthstone’s and Oak Valley’s reserves of 95% for proved developed producing (“PDP”) PV-10 reserves, 90% for proved developed non-producing (“PDNP”) PV-10 reserves, 65% for proved undeveloped (“PUD”) PV-10 reserves, and 50% for non-proved acreage. This comparable methodology applied to each company was utilized by Oak Valley only to calculate a proposed sharing
ratio of the combined company’s common stock in connection with a business combination, and Mr. Lodzinski noted that he did not necessarily regard such methodology as reflecting the fair market value of each company’s respective assets. The proposal also provided that Oak Valley’s cash contribution, which consisted of $107 million in then-undrawn equity commitments and $29.1 million of cash on hand, would be contributed to Earthstone in exchange for a number of Earthstone shares valued at a 3% discount to Earthstone’s 30-day volume-weighted average price per share (“VWAP”). At the time of the letter, Earthstone’s 30-day VWAP was $16.42. Mr. Lodzinski’s letter proposed that a majority of the Earthstone Board would be appointed by Oak Valley and that the existing management of Oak Valley would assume the executive leadership of Earthstone.
During October 2013, Mr. Singleton received a call from a third-party operator with Bakken assets. The third party suggested that Earthstone consider a three-way transaction involving Earthstone, the third party and another company. Due to the complicated structure, the limited assets held by the third party, the early-stage, conceptual nature of the proposed transaction, and the lack of significant management expertise in the third party, Mr. Singleton did not entertain further discussions. As noted below, Mr. Singleton contacted the third party again in April 2014 prior to executing a definitive agreement with Oak Valley, but by that time, the person with whom he had the initial discussions had left the company and a potential transaction was no longer being proposed.
On November 1, 2013, Earthstone held a special meeting of its Board of Directors to discuss Oak Valley’s proposal. Representatives from STRH and DGS also attended the meeting. At that meeting, representatives from DGS provided an overview of the Board’s fiduciary obligations in the context of a transaction such as the one proposed. STRH then provided an overview of Oak Valley, including a discussion of its management team and existing assets, which now included the properties acquired in Gonzales and Fayette Counties, Texas, an overview of Oak Valley’s October 22, 2013 proposal, a discussion of certain recently completed transactions in the oil and gas industry, and preliminary analyses of the financial terms of the Oak Valley proposal. STRH advised the Board that, because Earthstone had received limited information from Oak
Valley and had not yet had an opportunity to perform meaningful due diligence, more information would be needed about Oak Valley should the Board determine to pursue discussions regarding a potential transaction. The Board discussed the proposed transaction structure, valuation methodology, preliminary analyses of the financial terms of the Oak Valley proposal performed by STRH, and other information reflected in STRH’s presentation, including the implied sharing ratio based on transaction multiples involving companies in the oil and gas exploration and production industry. The Board made no determination as to whether the sharing ratio proposed by Oak Valley valued Earthstone’s assets at an appropriate value. It was also noted that Earthstone’s quarterly results would be released soon and that those results should also be considered in the context of any valuation discussion. Following additional discussion, the Board adjourned the meeting in order to further consider
the proposal and decided to reconvene at a later date.
On November 11, 2013, the Earthstone Board met again to discuss the Oak Valley proposal. The meeting was attended by representatives from DGS. The Board discussed certain possible drawbacks of the potential combination, including the amount of management’s attention that would be required to pursue the combination and the risk that the transaction could preclude a more attractive offer from some other party. The Board also discussed the unique potential upside that may accrue to the Earthstone stockholders as a result of the transaction, particularly given the recent successes that the Oak Valley management team has had in similar circumstances. In particular, the Board noted Mr. Lodzinski’s success in building GeoResources and selling it to Halcón Resources in 2012. It was noted that additional work needed to be conducted in order to understand the actual value of Oak Valley’s
properties and in particular whether the value attributed to non-proved and proved undeveloped acreage was appropriate given Oak Valley’s likely development schedule and budget. The Board also discussed the challenges of continuing to maintain its existing business strategy in light of Earthstone’s limited capital and human resources. It was noted that notwithstanding recent improvements in Earthstone’s financial performance, which have resulted primarily from investments made in prior years, the small size of the company and its relatively limited capital and human resources constrained its competitiveness and growth prospects, particularly given the increasing financial commitments required by Earthstone’s horizontal Bakken, pad-drilling program in North Dakota and by oil and gas exploration companies’ drilling resource plays in general. The Board concluded that it remained interested
in the potential benefits of the transaction, but that the exchange ratio proposed by Oak Valley was insufficient because, among other things, it did not value Earthstone’s assets at a high enough level and it calculated the number of shares issued for Oak Valley’s cash contribution at too low a price. It instructed Mr. Singleton to continue a dialogue with Oak Valley, but did not endorse negotiating a transaction with Oak Valley at that time. Later that week, on November 13, 2013, Mr. Singleton and representatives from DGS met with STRH representatives by telephone to convey the Board’s conclusion.
On December 10, 2013, Mr. Lodzinski, Mr. Anderson, Oak Valley’s Executive Vice President – Corporate Development and Engineering, and Tim Merrifield, Oak Valley’s Executive Vice President – Geology and Geophysics, traveled to Denver to meet with Earthstone’s Board of Directors at the DGS offices. All of the members of the Earthstone Board attended that meeting, as did representatives from STRH and DGS. Oak Valley gave a presentation on its management team and assets, including a detailed discussion of the Eagle Ford assets in Gonzales and Fayette Counties, Texas that were acquired by Oak Valley several months prior. Oak Valley described its reserves and proposed capital and drilling plans. Earthstone likewise provided an update on its activities during 2013 and its projected activities during 2014. Significant time was also spent discussing Oak Valley’s proposed valuation methodology,
although no modifications or concessions were made during the meeting. The nature of the meeting was primarily information gathering and due diligence. The parties did not specifically negotiate any terms of a potential transaction, although members of the Earthstone Board did convey their view that the sharing ratio proposed by Oak Valley was insufficient. In particular, the Board focused on the value ascribed to certain Oak Valley PUD reserves, suggesting that some of Oak Valley’s PUD reserves should be more heavily risk adjusted due to the lower likelihood of near-term production. The Board also argued that the value of some of Earthstone’s non-proved acreage should have been less risk adjusted due to the perceived higher likelihood of future production. In addition, the Board disagreed with the proposal to value Oak Valley’s cash infusion at a discount to Earthstone’s 30-day VWAP.
At the meeting, Mr. Lodzinski reiterated his view that, as part of a strategic combination, the Earthstone Board would be appointed by Oak Valley and that the existing management of Oak Valley would assume the executive leadership of Earthstone, although the retention of Mr. Singleton as an officer and member of the Board of Directors was suggested.
Following the departure of Oak Valley’s management team in the mid-afternoon, the Earthstone Board continued to discuss the proposed transaction informally for an additional two hours. Board members shared their views on the information provided by Oak Valley at that day’s meeting, and while no definitive decisions were reached regarding the transaction, Mr. Singleton was instructed to continue a dialogue with Oak Valley. In particular, it was noted that the Earthstone reserve information dated March 31, 2013 upon which Oak Valley based its proposal was quite dated and that both Oak Valley and Earthstone would soon have updated reserve reports. It was agreed that the transaction would be reconsidered after more current reserve reports became available.
During the weeks following the December 10, 2013 meeting, the parties exchanged additional information relating to properties, reserves, production and operations as well as financial, accounting and other matters.
On January 6, 2014, Mr. Singleton had a conference call with representatives from DGS and STRH to discuss next steps on the transaction. Mr. Singleton continued to express the view that discussions should continue, but that the proposed exchange ratio was insufficient. Although occasional discussions took place during January, February and March, the parties largely waited until updated reserve reports were available to re-invigorate their discussions.
In February 2014, Earthstone completed an internal update of its reserve report as of December 31, 2013 and circulated that report to Oak Valley. A summary of that report is set forth below:
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Oil
(MBbls)
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Gas
(MMcf)
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Total
(MBOE)
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Present Value Discounted
at 10% ($ in thousands) (1)
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Proved developed
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1,551 |
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1,694 |
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1,833 |
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$ |
43,115 |
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Proved developed non-producing
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|
57 |
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|
87 |
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|
|
72 |
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|
$ |
2,266 |
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Proved undeveloped
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|
|
1,022 |
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|
|
1,649 |
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|
|
1,296 |
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|
$ |
15,384 |
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Total proved
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|
2,630 |
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|
|
3,430 |
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|
3,201 |
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$ |
60,765 |
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Also in February 2014, Oak Valley’s reserve report as of December 31, 2013, prepared by CG&A, was circulated to Earthstone. At that time, Earthstone retained Ryder Scott to conduct a review of Oak Valley’s updated reserve report. A summary of that report is set forth below:
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Oil
(MBbls)
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Gas
(MMcf)
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NGL
(MBbls)
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Total
(MBOE)
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Present Value Discounted
at 10% ($ in thousands) (1)(2)
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Proved developed
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1,307 |
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11,053 |
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|
557 |
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3,706 |
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$ |
70,373 |
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Proved undeveloped
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4,771 |
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|
13,160 |
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|
|
761 |
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|
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7,726 |
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$ |
54,984 |
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Total proved
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6,078 |
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|
|
24,213 |
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|
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1,318 |
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|
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11,432 |
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$ |
125,357 |
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(1)
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Present Value Discounted at 10% (“PV-10”) is a non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV-10 is calculated without regard to future income taxes. Earthstone and Oak Valley management believe that the presentation of PV-10 value is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to the each company’s estimated proved reserves independent of its income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to its reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, Earthstone and Oak Valley believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, Earthstone and Oak Valley management use, and
believe the industry generally uses, the PV-10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
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(2)
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For presentation of the standardized measure of discounted future net cash flows, please see Note 11 – “Disclosures About Oil and Gas Producing Activities (Unaudited)” in the Notes to the Historical Consolidated Financial Statements of Oak Valley included in this proxy statement. The table below titled “Non-GAAP Reconciliation” provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.
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Non-GAAP Reconciliation (in thousands)
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The following table reconciles Oak Valley’s direct interest in oil and gas reserves as of December 31, 2013:
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Present value of estimated future net revenues (PV-10)
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$ |
125,357 |
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Pro forma future income taxes, discounted at 10% (3)
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(25,217 |
) |
Pro forma standardized measure of discounted future net cash flows
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$ |
100,140 |
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(3)
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Oak Valley is a partnership and is not subject to income taxes; a pro forma adjustment has been made to Oak Valley’s standardized measure to reflect the effect of income taxes.
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On March 24, 2014, Mr. Lodzinski sent an e-mail to Mr. Singleton with an updated indication of interest with respect to the proposed transaction, based on the parties’ updated comparative information, including (i) the risk-adjusted PV-10 value associated with Oak Valley’s independent reserve report and Earthstone’s internal report as of December 31, 2013, (ii) the risk-adjusted value associated with each company’s non-proved acreage, and (iii) each company’s net financial assets. Based on this analysis, Mr. Lodzinski proposed that the calculated sharing ratio for the combined company to be held by the existing Earthstone stockholders be 14.2%, compared to 10.6% in the October 2013 letter. Mr. Lodzinski further stated that for purposes of the latest indication of interest, Oak Valley chose to utilize the same
methodology as in the prior letter for purposes of calculating a proposed sharing ratio, and he intended to consider and analyze other market metrics and perhaps incorporate other methodologies in the analysis and negotiation, should the parties jointly choose to proceed. With respect to the analysis provided in the March 24, 2014 letter, there were various reasons the calculation resulted in an increase in the sharing ratio in favor of Earthstone, including the following:
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A decrease in the calculated risked net asset value of Oak Valley as a result of a reduction in its estimated PDP reserves (due to no newly drilled wells being put into production, production declines in completed wells that were steeper than previously anticipated, lower commodities pricing assumptions and higher operating expense assumptions) and a change in financial adjustments, which were partially offset by an increase in PUD reserves;
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An increase in the calculated risked net asset value of Earthstone as a result of an increase in estimated reserves due to the reclassification of PUDs to PDP status and an addition to PUDs as a result of drilling activity; and
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A decrease in the number of Earthstone shares to be issued in exchange for the Oak Valley cash infusion as a result of an increase in Earthstone’s stock price, notwithstanding Oak Valley’s desire that the number of Earthstone shares to be issued in exchange for the cash infusion be valued at a 3% discount to Earthstone’s 30-day VWAP. At the time of the March 24 letter, Earthstone’s 30-day VWAP was $20.93.
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The proposal provided that Oak Valley would select the members of the Earthstone Board, other than one seat, which would be filled initially by a current Earthstone director.
Mr. Singleton visited Houston on March 27 and 28, 2014. Mr. Singleton, Mr. Lodzinski and Mr. Anderson had dinner together on March 27, 2014, but held no substantive discussions regarding the transaction. On March 28, the same individuals met with representatives from Ryder Scott and CG&A to analyze and discuss Oak Valley’s December 31, 2013 reserve report. A representative from STRH also attended the meeting. The meeting was focused on gathering information regarding Oak Valley’s reserve report, and no substantive discussion was held regarding potential terms of the transaction.
On April 3, 2014, the Earthstone Board met again to discuss the transaction. Representatives from STRH and DGS also attended the meeting. The Board analyzed the methodology used by Oak Valley to arrive at the relative valuation for each company. Various adjustments were discussed, including the following:
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Calculating the number of shares to be issued in exchange for Oak Valley’s cash contribution at a price equal to Earthstone’s calculated risked net asset value, rather than at a discount to its 30-day VWAP;
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Risking both parties’ PV-10 value of their PDP acreage at 100%, rather than 95%; and
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Risking both parties’ unproved acreage at 25%, rather than at 50%.
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The cumulative effect of the proposed adjustments, if all were taken into account in calculating the relative valuations of Oak Valley and Earthstone, would result in Earthstone stockholders holding 17.5% of the combined company. STRH reviewed with the Board information showing how the proposed calculations of comparable risked net asset value compared to other valuation metrics and to comparable companies and selected recent transactions and also reviewed with the Board its analysis of the financial terms of Oak Valley’s March 24, 2014 updated indication of interest using the same valuation methodologies as those summarized below under “The Exchange – Opinion of Earthstone’s Financial Advisor.” The Board also discussed the alternatives to the proposed transaction, including continuing to pursue its existing growth strategy, seeking a sale of some or all of its assets
or opening a wider sales process to seek an alternative buyer for Earthstone. The Board discussed the pros and cons of initiating a wider sales process to seek alternative buyers. In particular, discussion was held regarding the intention of including a “go-shop” provision in the definitive agreement that would permit the company to seek alternative buyers after the agreement was announced. It was noted that under Oak Valley’s proposal, the composition of the board would be controlled by Oak Valley, with one seat initially held by a current Earthstone director. Given his intimate knowledge of Earthstone, Mr. Singleton was identified as the person to fill that role. Following further discussion, the Board ultimately expressed qualified support for a transaction in the range being discussed, particularly at the higher end of the range. The Board authorized Mr. Singleton and STRH to
continue discussions with Oak Valley. The Board also discussed creating a severance compensation plan for certain of the company’s employees that would provide a modest severance payment if an employee were terminated without cause following consummation of the transaction.
Following the meeting held on April 3, 2014, Mr. Singleton authorized STRH to propose a transaction to Oak Valley that would result in Earthstone stockholders retaining 17.5% of the combined company. On April 4, 2014, STRH emailed a proposal to Oak Valley consistent with the adjustments discussed at the meeting held on April 3, 2014.
On April 8, 2014, representatives of STRH met with Mr. Lodzinski and Mr. Anderson in New York, New York. At that meeting, the STRH representatives proposed that a transaction be structured with Earthstone stockholders retaining 17.5% of the combined company. Mr. Lodzinski and Mr. Anderson agreed to consider the proposal and to respond the following week.
On April 10, 2014, an attorney with DGS, contacted an attorney at Jones & Keller, P.C., who serves as legal counsel for Oak Valley. During that discussion, the representative from DGS summarized the outline of the definitive agreement, noting that Earthstone would propose that the definitive agreement include a “go-shop” provision. On April 14, 2014, the individuals spoke again and the representative from Jones & Keller advised that Oak Valley was considering the proposed exchange ratio and would respond soon. He also advised that Oak Valley would not consider a transaction that included a “go-shop” provision.
On April 16, 2014, Mr. Cohen sent an email to Mr. Singleton and STRH with a revised proposal. The revised proposal contemplated a transaction in which the Earthstone stockholders would hold 15.3% of the combined company. The primary modifications to Oak Valley’s prior proposal sent on March 24, 2014, included the following:
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risking the PV-10 value of the PDP acreage at 100%, rather than 95%, as was the case in the prior proposal;
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●
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reclassifying Oak Valley’s cash on hand of $34.3 million as part of Oak Valley’s risked net asset value calculation;
|
●
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reducing the number of shares to be issued in exchange for the $107 million cash infusion because of the increase in Earthstone’s 30-day VWAP to $21.06; and
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●
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modifying the methodology for valuing the non-proved acreage for each party.
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Given these changes, Earthstone’s proposed calculated risked net asset value increased to $49.8 million and Oak Valley’s increased to $130.0 million. In addition, the number of shares to be issued in exchange for Oak Valley’s cash infusion decreased from 7.04 million (in the March 24, 2014 proposal) to 5.08 million, due to the following:
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the reclassification of Oak Valley’s cash on hand;
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●
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the elimination of the 3% discount to Earthstone’s 30-day VWAP; and
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●
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the increase in Earthstone’s VWAP to $21.06.
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On April 18, 2014, DGS sent a draft definitive agreement for the transaction to Jones & Keller. The agreement contemplated that the proposed combination would be structured as a merger between wholly owned subsidiaries of Earthstone and Oak Valley. It also contained a “go-shop” provision and other customary “fiduciary out” provisions, including a proposed break fee of $1.0 million if Earthstone were to terminate the agreement to accept a superior proposal. The number of shares to be issued to Oak Valley and various other material terms were left blank in the draft agreement.
On Wednesday, April 23, 2014, an all-day meeting was held among the parties at the Denver, Colorado office of DGS. Attending the meeting were: Mr. Lodzinski, Mr. Anderson and Mr. Cohen from Oak Valley; Mr. Singleton, Melissa Temple, Earthstone’s Controller, and Andrew P. Calerich, one of Earthstone’s directors; and representatives from STRH, DGS and Jones & Keller. At that meeting, the parties provided an update on their respective activities since the last full in-person meeting held on December 10, 2013, and described the changes in the parties’ respective reserve estimates. The parties then discussed certain significant business points in the definitive agreement, including the “go-shop” provision and the amount of the proposed break-up fee. The composition of the board was briefly discussed, and it was agreed
that given the controlling ownership stake to be held by Oak Valley, it would select the members of the Earthstone board, although Mr. Singleton would retain his board seat. Composition of management was also discussed, and it was agreed that Mr. Singleton would fill some senior executive role following the transaction. Oak Valley also proposed that it be given significant flexibility prior to closing to enter into and consummate other asset or business acquisitions, with a corresponding adjustment to the number of shares to be issued to Oak Valley at closing. The parties then discussed the proposed sharing ratio. During the course of the discussion, it was noted that the basis on which Earthstone’s net assets had been calculated to that point included an incorrect number of estimated net acres held by Earthstone. After updating the Earthstone valuation with the correct net acres held, Oak Valley noted that the 15.3% proposal that it made in its April
16, 2014 letter should have been 14.6%. The existence of the “go-shop” provision was also a topic for significant discussion among the parties. Ultimately, Mr. Lodzinski stated that he would not enter into a transaction under any circumstances that included a “go-shop” provision. Following several rounds of negotiations throughout the day, the parties ultimately arrived at a tentative sharing ratio of 16% for Earthstone stockholders. Mr. Singleton agreed to take that proposal to the Earthstone Board, and the parties’ respective legal advisors were instructed to accelerate their remaining due diligence activities and to commence negotiations of the various definitive agreements.
On Friday, April 25, 2014, the Earthstone Board met to discuss the progress made in negotiations with Oak Valley. Representatives from STRH and DGS also attended that meeting. At that meeting, STRH noted that the 16% sharing ratio that was tentatively agreed to with Oak Valley was at the high end of the range that was previously considered by the Board, after updating the net acres held by Earthstone. STRH again reviewed with the Board materials showing how the proposed comparable risked net asset value compared to other valuation metrics and to comparable companies and selected recent transactions using the same valuation methodologies as those summarized below under “The Exchange – Opinion of Earthstone’s Financial Advisor.” The Board again discussed the pros and cons of the transaction, and in particular the disadvantages of proceeding without the contractual ability
to actively solicit other potential buyers after the execution of a definitive agreement. As it had done at prior meetings, the Board also discussed various alternatives to the “go-shop” provision, including possibly opening a wider sales process prior to executing a transaction with Oak Valley, and the potential risks posed by such a decision, such as the risk that Oak Valley would not continue to pursue the transaction. The Board ultimately agreed to forego the “go-shop” provision due to various considerations, including, among others, the inclusion of customary “fiduciary out” provisions in the draft exchange agreement, the relatively modest proposed break-up fee and Earthstone’s ability to discuss and negotiate unsolicited offers from third parties. Following discussion of the benefits of the proposed transaction, the Board authorized Mr. Singleton to continue negotiating the transaction with Oak Valley.
During April 2014, Mr. Singleton contacted the same third party that had inquired about a transaction in October 2013. At that time, the person with whom he had previously spoken had left the company, and the conceptual transaction was no longer being considered. In addition, one of the Earthstone board members noted that during March 2014 he had received tentative, informal interest from a private oil and gas company based in Denver, Colorado regarding the acquisition of some of Earthstone’s assets. The board member contacted this company during April 2014 to gauge its interest, but the message was not returned. After the public announcement of the exchange, the company again contacted Earthstone’s board member, and it became apparent that the
company was interested in acquiring only a small portion of Earthstone’s assets.
During the following two weeks, the parties conducted remaining due diligence. Earthstone retained a third-party consultant, John L. Obourn, Jr. & Co., to conduct property and title diligence on Oak Valley’s properties, while DGS conducted legal due diligence. From April 30, 2014 through May 2, 2014, Mr. Singleton traveled to Texas to meet with Oak Valley personnel and conduct on-site due diligence. Together, they conducted a site visit to Earthstone’s assets in south Texas on May 1, 2014 and then visited Oak Valley’s assets in Gonzales and Fayette Counties, Texas on May 2, 2014.
On April 30, 2014, Jones & Keller sent a revised draft of the definitive agreement to DGS. The definitive agreement was restyled as an exchange agreement, in which Oak Valley would contribute the Oak Valley Subsidiaries to Earthstone in exchange for shares of Earthstone. Jones & Keller also proposed a draft registration rights agreement by which Earthstone would agree to register for resale with the SEC on behalf of Oak Valley and its equity holders the shares received by Oak Valley in the exchange, and a draft voting agreement under which Mr. Singleton would agree to vote his shares in favor of the exchange, unless the exchange agreement was terminated prior to the Earthstone stockholder meeting.
On May 1, 2 and 3, 2014, various conversations took place among Earthstone, STRH and DGS. On May 2, 2014, a call occurred with representatives from Oak Valley, Earthstone, Jones & Keller, DGS and STRH in order to discuss the status and timing for remaining due diligence and certain open issues in the exchange agreement. On May 5, 2014, DGS sent a revised draft of the exchange agreement to Jones & Keller and Oak Valley. The most significant issues that remained subject to discussion and negotiation following that draft included: (i) the limitations on Oak Valley’s activities between signing and closing, and in particular, Oak Valley’s ability to enter into and consummate acquisitions of other assets or businesses during that period, (ii) the ability of Earthstone to terminate the transaction in the case of an “Intervening
Event,” (iii) the remedies available to Earthstone if Oak Valley’s members failed to fund their respective capital commitments at closing, and (iv) the number of shares to be authorized by Earthstone in its amendment to the certificate of incorporation and new equity incentive plan to be approved in connection with and as a condition of the exchange. Throughout these and all prior discussions with Earthstone, Mr. Lodzinski kept the Oak Valley board of managers advised, but none of the representatives of EnCap Investments L.P. serving on the Oak Valley board of managers, nor any other EnCap personnel or affiliates, participated in any of the discussions with the management or the Board of Directors of Earthstone.
On May 6 and 7, 2014, Mr. Singleton contacted each of the Earthstone directors to provide an update on negotiations and receive their input on the remaining open points.
On May 8, 2014, Jones & Keller sent a revised draft of the exchange agreement to DGS.
On May 9, 2014, various conversations took place among Earthstone, DGS and STRH. In the afternoon of Friday, May 9, 2014, representatives from Earthstone, Oak Valley, Jones & Keller, DGS and STRH reconvened by telephone to address the remaining open points in the exchange agreement. During this discussion, the parties agreed to certain limitations on Oak Valley’s ability to conduct acquisitions during the period prior to closing, the number of shares to propose that stockholders authorize in the amendment to the certificate of incorporation, a new equity incentive plan, and various other matters. The final significant issue to be resolved related to the remedies that would be available to Earthstone if Oak Valley’s members failed to fund
their capital commitment in order to satisfy the $107 million cash infusion by Oak Valley at closing. On May 11, 2014, DGS sent a revised draft of the exchange agreement to Jones & Keller and Oak Valley. On May 12, 2014, a further revised draft was circulated by Jones & Keller.
On May 13, 2014, the Earthstone Board of Directors met for approximately two and a half hours to consider the transaction. The meeting was also attended by representatives from DGS and STRH. At the meeting, a representative from DGS reminded the Board of its fiduciary duties in connection with the proposed transaction, consistent with the presentation on the subject that was delivered at a prior meeting. A representative from DGS then presented an overview of the due diligence investigation that was conducted by Earthstone personnel, DGS, and other consultants. The third-party consultant, John L. Obourn, Jr., noted his perceptions regarding the quality and completeness of Oak Valley’s land files and procedures. Next, DGS provided a summary of the exchange agreement and other transaction documents and noted the remaining points that were left to be negotiated. The Board’s input
was solicited on these remaining items. STRH then reviewed with the Board its financial analysis of the proposed transaction, which is summarized below under “The Exchange – Opinion of Earthstone’s Financial Advisor,” and rendered its opinion to the Board (solely in its capacity as such) to the effect that, as of that date and based upon and subject to the assumptions, qualifications and limitations stated in its opinion, the Exchange Consideration to be issued by Earthstone in the exchange pursuant to the exchange agreement was fair, from a financial point of view, to Earthstone. Next, Mr. Singleton summarized the projected results of Earthstone’s March 31, 2014 Ryder Scott reserve report and described the fairly modest differences between those results and management’s internal, December 31, 2013 report. He also noted that Ryder Scott’s review
of Oak Valley’s December 31, 2013 reserve report did not reflect any material variances in the reserve estimate that would impact the proposed valuation of Oak Valley for purposes of calculating the sharing ratio. Where forecasts, projections or estimates from Earthstone’s management were relied upon by STRH, such forecasts, projections or estimates were prepared by Earthstone’s chief executive officer, Ray Singleton, and its interim chief financial officer, Paul Maniscalco. Forecasts, projections and estimates of production, lease operating expenses and capital expenditures prepared by Earthstone’s management were consistent with the estimates used in the Earthstone Reserve Report or Earthstone Roll Forward Report, as applicable.
The Board continued to engage in extensive discussions regarding the proposed transaction. In particular, it considered the alternative of remaining independent. The Board discussed, as it had done at prior meetings, the limited capital and human resources available to the company and noted the possibility of having to access the capital markets in the next year or two in order to continue to fund the anticipated drilling program on Earthstone’s properties. The challenge of raising capital in the current market given the company’s size and scope was noted. The Board considered that a larger company with larger capital availability and human resources should permit Earthstone to take advantage of acquisition and development opportunities that are currently unavailable
to it. The Board also noted that the relatively small working interest position that Earthstone held made it unlikely in its view that an existing operator of the assets would be interested in undertaking a corporate acquisition of Earthstone at a valuation in excess of that proposed by Oak Valley. The Board also discussed the background of Mr. Lodzinski and his significant experience and track record in the oil and gas industry. In addition, the Board considered the negative consequences of entering into the exchange agreement, including the time and distraction associated with consummating such a transaction, and the possibility that the transaction may not be consummated. In considering the sharing ratio, the Board concluded that the relative values of Earthstone and Oak Valley, and the corresponding sharing ratio for the combined company, was attractive to the existing Earthstone stockholders and noted that the significant capital to be contributed at closing by
Oak Valley should place Earthstone in a strong position to grow through acquisitions and drilling.
Following these presentations and further discussions, the Earthstone Board concluded that the exchange agreement and the transactions contemplated thereby were in the best interest of Earthstone and its stockholders and unanimously approved the exchange agreement and the transactions contemplated thereby. The Board resolved to recommend that the stockholders of Earthstone approve the issuance of Earthstone common stock pursuant to the exchange agreement. The Board also approved amendments to the Earthstone shareholder rights plan in order to permit the consummation of the exchange, and termination of the shareholder rights plan upon consummation of the exchange.
Jones & Keller and DGS proceeded to finalize the exchange agreement, registration rights agreement and voting agreement on May 14, 2014. On May 15, 2014, the shareholder rights plan was amended, the exchange agreement and voting agreement were executed, and the parties issued a joint press release announcing the transaction.
Recommendation of the Earthstone Board and Reasons for the Exchange
The Earthstone Board met approximately eight times over the course of a year to consider and discuss the proposed transaction. After due consideration and consultation with its legal and financial advisors, the Earthstone Board has unanimously:
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determined that the transactions contemplated by the exchange agreement, including the issuance of Earthstone common stock and the reconfiguration of the Earthstone Board and management to be controlled by Oak Valley or persons nominated or designated by Oak Valley upon completion of the transactions contemplated in the exchange agreement, were in the best interests of Earthstone and its stockholders from a financial and procedural point of view;
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approved the exchange agreement;
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directed that the issuance of Earthstone shares pursuant to the exchange agreement be submitted for consideration by the Earthstone stockholders, as well as (i) a proposal to increase the authorized capital stock of Earthstone from 6,400,000 shares of common stock and 600,000 shares of preferred stock to 100,000,000 shares of common stock and 20,000,000 shares of preferred stock, and (ii) a proposal to approve and adopt the 2014 Plan, which, among other things, reserves 750,000 shares for issuance under the plan; and
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recommended that Earthstone’s stockholders vote in favor of the issuance of Earthstone shares pursuant to the exchange agreement, in favor of the proposal to amend the certificate of incorporation to increase Earthstone’s authorized capital stock, in favor of the proposal to approve and adopt the 2014 Plan, and in favor of the proposal to approve, by a non-binding advisory vote, the Severance Plan.
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In reaching the determinations set forth above, the Earthstone Board considered a variety of business, financial and market factors based upon, among other items, (i) the Board’s familiarity with the business and operations of Earthstone and the industry in which it operates, (ii) management reports and presentations regarding Earthstone and its properties and assets, financial condition, competitive position, business strategy and prospects, (iii) economic and market conditions as they relate to the oil and gas industry, both on a historical and on a prospective basis, and (iv) a careful review of the terms and conditions of the transaction contemplated by the exchange agreement. In particular, the Board considered the positive factors set forth below:
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The fact that Earthstone is a very small public company, with limited financial and human resources and limited ability to access debt and equity capital. The combination with Oak Valley provides an opportunity to alleviate these limitations.
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The past success of Oak Valley’s management team in creating significant shareholder value for smaller public companies. During Mr. Lodzinski’s career, he has successfully grown and sold several oil and gas companies, including GeoResources, Inc., Southern Bay Energy, LLC, AROC, Inc., Texoil, Inc., and Hampton Resources Corporation, in each case realizing substantial returns for investors.
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The fact that the relative net asset valuations of Oak Valley and Earthstone that were considered, in part, in order to determine the relative sharing ratio of the combined company were viewed as attractive to the Earthstone stockholders.
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The expectation that the combination of Earthstone and Oak Valley will provide Earthstone with an opportunity to increase its asset size and diversify its asset base. Oak Valley’s oil and gas properties are located primarily in the Eagle Ford resource play in south Texas, whereas Earthstone’s assets are located primarily in the Montana and North Dakota portions of the Williston Basin.
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The additional capital that will be contributed into the Oak Valley Subsidiaries at the closing of the exchange will be no less than $100 million (although a portion of that may be committed by Oak Valley prior to closing in the event of interim acquisitions), providing the combined company with substantial funds to finance oil and gas exploratory and development activities.
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The greater access to the capital markets available to the combined company as a result of its increased market capitalization and reserve and production profile.
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The opportunities for administrative and operational economies of scale and cost savings for the combined company, although such savings are difficult to quantify. In the current industry environment of high demand for personnel, the combined company should have a full complement of capable staff across all industry disciplines, including engineering, geology and geophysics, land, marketing, drilling, completion, operations, administration, regulatory, accounting and finance. This broader employee base should be of benefit to Earthstone and its stockholders.
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The increased interest of securities analysts and institutional investors in a larger entity, making it potentially easier for the combined company to raise capital on more favorable terms and potentially increasing trading volume, and, as a result, liquidity, of Earthstone common stock over time.
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The financial and other terms and conditions of the exchange agreement, which is the product of extensive deliberations and analysis, including among other things, over one year of specific consideration by the Earthstone Board, the input of independent advisors and extensive negotiations between Earthstone and Oak Valley, including:
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the fact that Earthstone is permitted to furnish information to and conduct negotiations with third parties regarding an alternative acquisition proposal in certain circumstances;
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the fact that Earthstone is permitted to terminate the exchange agreement in order to accept a competing proposal proposed by a third party that is a superior proposal upon the payment to Oak Valley of the termination fee (see “The Exchange Agreement – Termination Fee”) subject to compliance with the exchange agreement; and
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the Earthstone Board’s belief, after consultation with its legal and financial advisors, that the $1.0 million termination fee (which is approximately 2.7% of the equity value of Earthstone) that may become payable (and the circumstances when such amounts are payable) in the event that the exchange agreement is terminated under certain circumstances is reasonable in light of the facts and circumstances surrounding the exchange, the benefits of the exchange and commercial practice.
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The fact that the exchange would not create a taxable event for the Earthstone stockholders.
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The financial opinion of STRH relating to the fairness from a financial point of view of the consideration to be paid by Earthstone in connection with the exchange, as more fully described below, under “The Exchange – Opinion of Earthstone’s Financial Advisor.”
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The belief that there was a high probability that the transaction would be successfully completed on the agreed-upon terms once a definitive agreement was executed based on the Board’s knowledge of Oak Valley’s business, operations, management, reputation and financial condition.
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The Earthstone Board also considered potentially negative factors concerning the exchange agreement, including the following:
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The potential difficulties associated with combining the business enterprises of Earthstone and Oak Valley, and the possibility that, as a result, the anticipated benefits to Earthstone and its stockholders might not be fully realized.
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The risk that entering into the exchange agreement could result in a loss of interest by other parties to make a definitive proposal for the acquisition of Earthstone, particularly in light of the $1.0 million termination fee to be paid to Oak Valley if the Earthstone Board approves and recommends an acquisition proposal from another entity in certain other circumstances.
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The restrictions in the exchange agreement on the operation of Earthstone’s business during the period between the signing of the exchange agreement and the completion of the transactions contemplated by the exchange agreement, which include limitations on incurring debt, entering into material contracts and acquiring or selling assets, thereby limiting Earthstone’s ability to pursue significant business opportunities unilaterally during this period, which might have resulted in greater returns to Earthstone stockholders than those expected from the exchange agreement.
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The possibility that the financial market’s perception of the proposed transactions could lead to a decrease in the trading price of the Earthstone common stock, thereby potentially reducing the long-term equity value of Earthstone if the proposed transactions are not completed.
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The significant cost involved in connection with negotiating and completing the exchange agreement, and the substantial amount of management time and effort required to effect the transactions contemplated by the exchange agreement, particularly since Earthstone’s management has many other responsibilities due to Earthstone’s small size.
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The Board also considered the likelihood of the existence of an alternative buyer willing to combine with Earthstone or acquire the company or its assets for cash at a valuation superior to that proposed by Oak Valley. As described above in “The Exchange – Background of the Exchange,” the Board was determined to seek in the definitive exchange agreement the inclusion of a “go-shop” provision that would permit the company to solicit other potential bidders following execution of the exchange agreement but prior to closing of the exchange. During the course of negotiation, the inclusion of such a provision was the subject of much discussion and debate. Oak Valley remained insistent that it would not enter into a transaction that included
a “go-shop” provision. The Board ultimately concluded, in light of the various factors described above, including the inclusion of customary “fiduciary out” provisions, the relatively modest break-up fee and Earthstone’s ability to discuss and negotiate unsolicited offers from third parties, that the exchange was in the best interest of the Earthstone stockholders notwithstanding the company’s inability to actively solicit alternative buyers following execution of the exchange agreement.
The foregoing discussion of the information and factors considered by the Earthstone Board is not exhaustive, but includes material factors considered by the Earthstone Board. In view of the wide variety of factors considered by the Earthstone Board in connection with its evaluation of the exchange agreement and the complexity of such matters, the Earthstone Board did not consider it practical, nor did it attempt, to quantify, rank or otherwise assign relative weights to the specific factors that it considered in reaching a decision. The Earthstone Board discussed the factors described above, asked questions of Earthstone’s management and Earthstone’s legal and financial advisors and reached consensus that the exchange agreement was in the best interests of the Earthstone stockholders. In considering the factors described above, individual members of the Earthstone Board may have given different weight to different factors
and may have applied different analyses to each of the material factors considered by the Earthstone Board.
Opinion of Earthstone’s Financial Advisor
Earthstone retained STRH to serve as Earthstone’s financial advisor in connection with the exchange and to provide the Board of Directors (solely in its capacity as such) with an opinion with respect to the fairness, from a financial point of view, to Earthstone of the Exchange Consideration to be issued by Earthstone in the exchange pursuant to the exchange agreement. For purposes of STRH’s opinion, the term “Exchange Consideration” means an aggregate of approximately 9.12 million shares of Earthstone common stock, subject to certain adjustments as set forth in the exchange agreement, to be issued to Oak Valley, and the term “exchange” means the transfer by Oak Valley of all equity interests in each of the three Oak Valley Subsidiaries to Earthstone, and in consideration of such contribution, Earthstone’s issuance to Oak
Valley of the Exchange Consideration.
On May 13, 2014, STRH rendered its opinion to the Board (solely in its capacity as such) to the effect that, as of that date and based upon and subject to the assumptions, qualifications and limitations stated in its opinion, the Exchange Consideration to be issued by Earthstone in the exchange pursuant to the exchange agreement was fair, from a financial point of view, to Earthstone.
The summary of STRH’s opinion in this proxy statement is qualified in its entirety by reference to the full text of its written opinion, which is attached hereto as Annex C and sets forth the procedures followed, assumptions made, qualifications and limitations on the review undertaken and other matters considered by STRH in preparing its opinion. STRH’s opinion was rendered at the request of the Board and was for the use and benefit of the Board (solely in its capacity as such) in connection with its consideration of the exchange, and neither STRH’s opinion nor the summary of its opinion and the related analyses summarized in this proxy statement is intended to be, and they do not constitute, advice or a recommendation to the Board, any security holder of Earthstone, or any other person or entity as to how to act or vote with respect to any matter relating to the exchange or otherwise.
In arriving at its opinion, STRH reviewed:
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certain publicly available business and financial information relating to Earthstone and Oak Valley;
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the historical reported price and historical trading activity for the shares of the Earthstone common stock;
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certain other information relating to the historical, current and future business, financial condition, results of operations and prospects of Earthstone made available to STRH by Earthstone, including certain financial projections prepared by the management of Earthstone relating to Earthstone (the “Earthstone Projections”);
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certain other information relating to the historical, current and future business, financial condition, results of operations and prospects of the Oak Valley Subsidiaries made available to STRH by Oak Valley, including certain financial projections prepared by the management of Oak Valley relating to the Oak Valley Subsidiaries (the “Oak Valley Subsidiaries Projections”);
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the current and projected financial and operating performance of Earthstone and the Oak Valley Subsidiaries as compared to that of other companies with publicly traded equity securities that STRH deemed relevant;
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a reserve report prepared by Earthstone’s independent oil and gas reserve engineers with respect to the proved developed producing, proved developed non-producing, and proved undeveloped oil and natural gas reserve production data for the business and corresponding pricing data as of March 31, 2013 (the “Earthstone Reserve Report”), as rolled forward by the management of Earthstone and reviewed by Earthstone’s independent oil and gas reserve engineers as of January 1, 2014 (the “Earthstone Roll Forward Report”);
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a reserve report prepared by Oak Valley’s independent oil and gas reserve engineers with respect to the proved developed producing, proved developed non-producing, proved undeveloped, and probable and possible oil and natural gas reserve production data for the Oak Valley Subsidiaries and corresponding pricing data as of January 1, 2014 (the “Oak Valley Reserve Report”); and
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the publicly available financial terms of certain transactions which STRH deemed relevant.
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In addition, STRH had discussions with certain members of the managements of Earthstone and the Oak Valley Subsidiaries regarding the business, financial condition, results of operations, and prospects of Earthstone and the Oak Valley Subsidiaries, respectively, and the exchange and undertook such other studies, analyses and investigations as STRH deemed appropriate.
STRH assumed and relied upon, without independent verification, the accuracy and completeness of all data, material and other information furnished, or otherwise made available, to STRH, discussed with or reviewed by STRH, or publicly available, including without limitation, the Earthstone Reserve Report, the Earthstone Roll Forward Report, and the Oak Valley Reserve Report, and did not assume any responsibility with respect to such data, material and other information. STRH’s role in reviewing such data, material and other information was limited solely to performing such review as it deemed necessary and appropriate to support its opinion. In addition, the management of Earthstone advised STRH, and STRH assumed, that the Earthstone Projections were reasonably prepared in good faith on bases reflecting the best currently available estimates and judgments of the management of Earthstone as to the future
financial results and condition of Earthstone. In addition, the management of Oak Valley advised STRH, and STRH assumed, that the Oak Valley Subsidiaries Projections were reasonably prepared in good faith on bases reflecting the best currently available estimates and judgments of the management of Oak Valley as to the future financial results and condition of the Oak Valley Subsidiaries. STRH expressed no opinion with respect to the Earthstone Projections or the Oak Valley Subsidiaries Projections, or the assumptions on which they were based, or any other assumptions discussed in the opinion. STRH is not an oil or natural gas reserve valuation expert and did not express any opinion with respect to such
subject matter. If the conclusions set forth in the Earthstone Reserve Report, the Earthstone Roll Forward Report, or the Oak Valley Reserve Report were not accurate, the conclusions set forth in STRH’s opinion could be materially affected. STRH relied upon and assumed, without independent verification, that there had been no change in the business, assets, liabilities, financial condition, results of operations, cash flows or prospects of Earthstone or the Oak Valley Subsidiaries since the date of the most recent financial statements and other information, financial or otherwise, provided to STRH and that there was no information, facts or circumstances that would make any of the information discussed with or reviewed by STRH inaccurate, incomplete or misleading. STRH relied upon and assumed, without independent verification, that (a) the representations and warranties of all parties
to the exchange agreement were true and correct; (b) each party to the exchange agreement would fully and timely perform all of the covenants and agreements required to be performed by such party under the exchange agreement; (c) all conditions to the consummation of the exchange would be satisfied without waiver thereof; (d) the exchange would be consummated in accordance with the terms of the exchange agreement without waiver, modification or amendment of any term, condition or agreement therein; and (e) in the course of obtaining any regulatory or third-party consents, approvals or agreements in connection with the exchange, no delay, limitation, restriction or condition would be imposed that would have an adverse effect on Earthstone or the Oak Valley Subsidiaries or the expected benefits of the exchange. In addition, STRH assumed that the exchange agreement, when executed by
the parties thereto, would conform to the draft reviewed by STRH in all respects material to its analysis and its opinion.
Furthermore, in connection with its opinion, STRH was not requested to make, and did not make, any physical inspection or independent appraisal or evaluation of any of the assets, properties or liabilities (fixed, contingent, derivative, off-balance-sheet or otherwise) of Earthstone or the Oak Valley Subsidiaries or any other person or entity, nor was STRH provided with any such appraisal or evaluation, other than the Earthstone Reserve Report, the Earthstone Roll Forward Report, and the Oak Valley Reserve Report. STRH undertook no independent analysis of any potential or actual litigation, regulatory action, possible unasserted claims or other contingent liabilities to which Earthstone, the Oak Valley Subsidiaries, or any other person or entity
is or may be a party or is or may be subject, or of any governmental investigation of any possible unasserted claims or other contingent liabilities to which Earthstone or the Oak Valley Subsidiaries is or may be a party or is or may be subject. STRH was not requested to, and did not, solicit any indications of interest from third parties with respect to the acquisition of all or any portion of Earthstone, or control thereof, or any other party, or any alternatives to the exchange.
STRH’s opinion was necessarily based on financial, economic, monetary, market and other conditions as in effect on, and the information made available to it as of, the date of its opinion. STRH has no obligation to update, revise, reaffirm or withdraw its opinion or otherwise comment upon events occurring or information that becomes available after the date of its opinion.
STRH’s opinion only addressed the fairness, from a financial point of view, of the Exchange Consideration to be issued by Earthstone pursuant to the exchange agreement and did not address any other term, aspect or implication of the exchange or any agreement, arrangement or understanding entered into in connection therewith or otherwise. STRH was not requested to opine as to, and its opinion does not express an opinion as to or otherwise address, among other things: (i) the underlying business decision of Earthstone, its security holders or any other person or entity to proceed with or effect the exchange; (ii) the form, structure or any other portion or aspect of, the exchange; (iii) the fairness of any portion, term, aspect or implication of the exchange to the holders of equity or debt of Earthstone, or any particular holder of securities, creditors or other constituencies of Earthstone, or to any other person or entity;
(iv) the relative merits of the exchange as compared to any alternative business strategies that might exist for Earthstone or any other person or entity or the effect of any other transaction in which Earthstone or any other person or entity might engage; (v) whether or not Earthstone or any other person or entity is paying reasonably equivalent value in the exchange under any applicable laws relating to bankruptcy, insolvency, fraudulent conveyance or similar matters; (vi) the solvency, creditworthiness, viability, ability to pay debts when due, or fair value of Earthstone or any other participant in the exchange, or any of their respective assets, including under any applicable laws relating to bankruptcy, insolvency, fraudulent conveyance or similar matters, or the impact of the exchange on such matters; or (vii) the fairness, financial or otherwise, or the amount, nature or any other aspect of any compensation or consideration payable to or received by any officers,
directors or employees of any party to the exchange or any class of such persons, relative to the Exchange Consideration or otherwise. In addition, STRH expressed no opinion as to the Oak Valley Interim Acquisitions (as defined in the exchange agreement), if any, or as to any adjustment in the Exchange Consideration or in the amount of cash to be contributed by Oak Valley to the Oak Valley Subsidiaries pursuant to Section 5.2(b) of the exchange agreement. Furthermore, no opinion, counsel or interpretation was intended in matters that require legal, regulatory, accounting, tax or other similar professional advice. STRH assumed that such opinions, counsel or interpretations were or would be obtained from appropriate professional sources. Furthermore, STRH relied, with the Board’s consent, on the assessments by Earthstone, the Board, and their respective advisors as to all legal, regulatory,
accounting, and tax matters with respect to Earthstone and the exchange.
STRH acted as financial advisor to Earthstone in connection with the exchange and will receive an aggregate fee for its services in the amount of $1.0 million, a portion of which was payable upon delivery of its opinion and a substantial portion of which is contingent upon the consummation of the exchange. In addition, Earthstone agreed to reimburse certain of STRH’s expenses and to indemnify it and certain related parties for certain liabilities arising out of STRH’s engagement. STRH and its affiliates (including SunTrust Bank) may in the future provide, investment banking, investment management, treasury management, wealth management and other financial services to Earthstone and its affiliates and associates for which STRH and its affiliates would expect to receive compensation. STRH and its affiliates (including SunTrust Bank) have not provided Oak Valley or EnCap Investments L.P. (which is an affiliate of Oak Valley)
with any financial advisory or financing services during the prior two years, but may have in the past provided and are currently providing investment banking, investment management, treasury management, wealth management and other financial services to certain affiliates and portfolio companies of EnCap Investments L.P., for which STRH and its affiliates have received and would expect to receive compensation, and may in the future provide such services to Oak Valley and/or its affiliates for which STRH and its affiliates would expect to receive compensation.
STRH is a full service securities firm engaged in securities trading and brokerage activities as well as providing investment banking and other financial services. In the ordinary course of business, STRH and its affiliates (including SunTrust Bank) may acquire, hold or sell, for STRH’s and its affiliates’ own accounts and the accounts of customers, equity, debt and other securities and financial instruments (including bank loans and other obligations) of Earthstone, Oak Valley, their respective affiliates and any other party that may be involved in the exchange, as well as provide investment banking and other financial services to such persons or entities, including for which STRH and its affiliates would expect to receive compensation. In addition, STRH and its affiliates (including SunTrust Bank) may have other financing and business relationships with Earthstone, Oak Valley, their respective affiliates and associates and
any other person or entity that may be involved with the exchange.
STRH’s opinion was directed to the Board (solely in its capacity as such) in connection with its evaluation of the exchange. STRH’s opinion should not be construed as creating any fiduciary duty on the part of STRH to any person or entity. STRH’s opinion was not intended to be, and did not constitute, a recommendation to the Board, any security holder of Earthstone, or any other person or entity as to how to act or vote with respect to any matter relating to the exchange or otherwise. The issuance of STRH’s opinion was approved by an internal committee of STRH authorized to approve opinions of such nature.
The following is a summary of the material financial analyses performed by STRH in connection with its opinion rendered to the Board on May 13, 2014. The analyses summarized below include information presented in tabular format. The tables alone do not constitute a complete description of the analyses. Considering the data in the tables below without considering the full narrative description of the analyses, as well as the methodologies underlying, and the assumptions, qualifications and limitations affecting, each analysis, could create a misleading or incomplete view of STRH’s analyses.
Selected Company Analysis
STRH reviewed and compared financial and operating data relating to Earthstone and Oak Valley with selected companies that STRH deemed comparable to Earthstone and Oak Valley, based on its experience in the exploration and production industry. STRH reviewed the public stock market trading multiples for the following exploration and production companies, which are collectively referred to as the “Selected Companies” and which STRH selected because their operating and financial characteristics are similar in certain respects to Earthstone and the Oak Valley Subsidiaries, including in terms of market capitalization, enterprise value, geography and size and characteristics of oil and gas reserves and production:
●
|
Abraxas Petroleum Corporation;
|
●
|
American Eagle Energy Corporation;
|
●
|
Black Ridge Oil & Gas, Inc.;
|
●
|
Lonestar Resources Limited;
|
●
|
Northern Oil and Gas, Inc.;
|
●
|
PrimeEnergy Corporation;
|
●
|
Red Mountain Resources, Inc.; and
|
Using publicly available information, STRH calculated and analyzed ratios for Earthstone and the Selected Companies as follows:
●
|
enterprise value, defined as the market value of its common stock using its closing stock price as of May 9, 2014 and most recently available fully-diluted share count, plus its outstanding net debt, and the book value of any minority interest, divided by proved reserves (on a BOE basis assuming a conversion ratio of natural gas to oil of 6 Mcf to 1 Bbl), referred to below as “Enterprise Value/Proved Reserves”;
|
●
|
enterprise value divided by proved developed reserves (“PD Reserves”) (on a BOE basis), referred to below as “Enterprise Value/PD Reserves”;
|
●
|
enterprise value divided by latest daily production (on a BOE per day (“BOEpd”) basis), referred to below as “Enterprise Value/Production”;
|
●
|
enterprise value divided by the estimated future cash flow, discounted at a rate of 10% per annum, with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC (“PV-10”), referred to below as “Enterprise Value/PV-10”;
|
●
|
enterprise value divided by estimated earnings before interest, taxes, depreciation and amortization (“EBITDA”) for 2014 based on consensus equity research analyst estimates as provided by Capital IQ, referred to below as “Enterprise Value/2014E EBITDA”; and
|
●
|
enterprise value divided by EBITDA for 2015 based on consensus equity research analyst estimates as provided by Capital IQ, referred to below as “Enterprise Value/2015E EBITDA.”
|
The results of the Selected Company Analysis are summarized below:
Selected Companies Ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
|
$9.80 |
|
|
|
$15.96 |
|
|
|
$15.55 |
|
|
|
$23.21 |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
|
$19.43 |
|
|
|
$40.37 |
|
|
|
$42.86 |
|
|
|
$70.47 |
|
Enterprise Value/Production ($ / BOEpd)
|
|
|
$70,034 |
|
|
|
$105,469 |
|
|
|
$100,055 |
|
|
|
$151,468 |
|
Enterprise Value/PV-10
|
|
|
0.65 |
x |
|
|
0.95 |
x |
|
|
0.93 |
x |
|
|
1.38 |
x |
Enterprise Value/2014E EBITDA
|
|
|
3.8 |
x |
|
|
5.4 |
x |
|
|
5.2 |
x |
|
|
7.4 |
x |
Enterprise Value/2015E EBITDA
|
|
|
2.7 |
x |
|
|
4.1 |
x |
|
|
4.0 |
x |
|
|
5.6 |
x |
STRH selected the companies listed above because their business and operating profiles are similar in certain respects to that of Earthstone and the Oak Valley Subsidiaries. However, because of the inherent differences between the business, operations and prospects of Earthstone and the Oak Valley Subsidiaries and those of the Selected Companies, STRH believed that it was inappropriate to, and therefore did not, rely solely on the quantitative results of the Selected Company Analysis. Accordingly, STRH also made qualitative judgments concerning differences between the business, financial and operating characteristics and prospects of Earthstone, the Oak Valley Subsidiaries
and the Selected Companies.
Using the reference ranges for the benchmarks set forth below and the corresponding financial or operating statistics and certain other balance sheet information for Earthstone as provided by Earthstone management, STRH derived implied equity values for Earthstone also as set forth below (rounded to the nearest one million dollars), compared in each case to Earthstone’s market capitalization as of May 9, 2014 of approximately $37 million and Earthstone’s estimated net asset value (calculated as summarized below) of approximately $46 million:
|
|
|
|
|
Approximate
Implied Equity Value*
($ in millions)
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$12 per BOE - $20 per BOE
|
|
|
$33 - $58 |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$32 per BOE - $52 per BOE
|
|
|
$55 - $93 |
|
Enterprise Value/Production ($ / BOEpd)
|
|
$85,000 per BOEpd - $115,000 per BOEpd
|
|
|
$45 - $63 |
|
Enterprise Value/PV-10
|
|
0.9x – 1.1x |
|
|
$49 - $61 |
|
Enterprise Value/2014E EBITDA
|
|
5.0x – 6.0x |
|
|
$36 - $44 |
|
Enterprise Value/2015E EBITDA
|
|
3.5x – 4.5x |
|
|
$31 - $42 |
|
* Equity value derived as enterprise value minus outstanding net debt.
Using the reference ranges for the benchmarks set forth below and the corresponding financial or operating statistics and certain other balance sheet information for the Oak Valley Subsidiaries as provided by Oak Valley’s management and including the approximately $107 million in cash in uncalled equity commitments, STRH derived implied equity values for the Oak Valley Subsidiaries also as set forth below (rounded to the nearest one million dollars), compared to the Oak Valley Subsidiaries’ estimated net asset value (calculated as summarized below) of approximately $237 million:
|
|
|
|
|
Approximate
Implied Equity Value*
($ in millions)
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$12 per BOE - $20 per BOE
|
|
|
$264 - $355 |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$32 per BOE - $52 per BOE
|
|
|
$245 - $319 |
|
Enterprise Value/Production ($ / BOEpd)
|
|
$85,000 per BOEpd - $115,000 per BOEpd
|
|
|
$309 - $373 |
|
Enterprise Value/PV-10
|
|
0.9x – 1.1x |
|
|
$240 - $265 |
|
Enterprise Value/2014E EBITDA
|
|
5.0x – 6.0x |
|
|
$304 - $339 |
|
Enterprise Value/2015E EBITDA
|
|
3.5x – 4.5x |
|
|
$413 - $495 |
|
* Equity value derived as enterprise value minus outstanding net debt.
Selected Transaction Analysis
STRH reviewed and compared the transaction values and financial multiples paid in selected other transactions that STRH deemed relevant, based on its experience with merger and acquisition transactions in the exploration and production industry. STRH chose such transactions based on, among other things, the similarity of the applicable target in each transaction to Earthstone and the Oak Valley Subsidiaries with respect to size, location of assets, characteristics of oil and gas reserves and other characteristics that STRH deemed relevant. In particular, STRH selected, from the IHS Herold database, certain transactions announced since February 28, 2011 with values between $21 million and $260 million that involved acquisitions of exploration and production and related assets
in certain U.S. locations, and excluded enhanced oil recovery transactions, predominantly acreage transactions and drop-down transactions between related entities.
The following list sets forth the transactions analyzed (and the date each transaction was announced), which are collectively referred to as the “Selected Transactions”:
|
|
|
|
|
|
Primarily Operated vs. Primarily Non-Operated*
|
|
|
Memorial Product Partners LP
|
|
Alta Mesa Holdings, LP
|
|
Eagle Ford
|
|
Non-Operated
|
|
|
Lonestar Resources, Inc.
|
|
Undisclosed company(ies)
|
|
Eagle Ford
|
|
Operated
|
|
|
New Standard Energy Limited
|
|
Magnum Hunter Resources Corporation; Outback Energy Hunter Pty Ltd; Pathfinder Onshore Group
|
|
Eagle Ford
|
|
Operated
|
|
|
Redman Resources, LLC
|
|
Abraxas Petroleum Corporation†
|
|
Eagle Ford
|
|
Non-Operated
|
|
|
Black Ridge Oil & Gas, Inc.
|
|
Undisclosed private company(ies)
|
|
Bakken
|
|
Non-Operated
|
|
|
Argent Energy Trust
|
|
Undisclosed private company(ies)
|
|
Rocky Mountain
|
|
Operated
|
|
|
Undisclosed company(ies)
|
|
Emerald Oil, Inc.† ⌂
|
|
Bakken
|
|
Non-Operated
|
|
|
Gastar Exploration Ltd.
|
|
Lime Rock Resources
|
|
Hunton
|
|
Operated
|
|
|
Oasis Petroleum Inc.
|
|
Magnum Hunter Resources Corp.
|
|
Bakken
|
|
Operated
|
|
|
Whiting Petroleum Corporation
|
|
Undisclosed private company(ies)
|
|
Bakken
|
|
Operated
|
|
|
Triangle Petroleum Corporation
|
|
Kodiak Oil & Gas Corp.
|
|
Bakken
|
|
Operated
|
|
|
Undisclosed company(ies)
|
|
Halcón Resources Corporation
|
|
Eagle Ford
|
|
Operated
|
|
|
Triangle Petroleum Corporation
|
|
Undisclosed company(ies)
|
|
Bakken
|
|
Operated
|
|
|
Corinthian Exploration Corp.
|
|
Surge Energy Inc.† ⌂
|
|
Bakken
|
|
Non-Operated
|
|
|
Aurora Oil and Gas Limited
|
|
Undisclosed company(ies)
|
|
Eagle Ford
|
|
Operated
|
|
|
Shoreline Energy Corp.
|
|
Undisclosed company(ies) ‡
|
|
Rocky Mountain
|
|
Non-Operated
|
|
|
Lonestar Resources, Inc.
|
|
Undisclosed company(ies)† ‡
|
|
Eagle Ford
|
|
Operated
|
|
|
Buyer
|
|
Seller
|
|
Primary Location
|
|
Primarily Operated vs. Primarily Non-Operated* |
|
Announcement Date
|
Resolute Energy Corporation
|
|
Caprock Land & Cattle, LLC; Celero Energy II, LP; Undisclosed private company(ies)
|
|
Permian
|
|
Non-Operated
|
|
|
WellStar Energy Corp.
|
|
Undisclosed company(ies)† ⌂
|
|
Bakken
|
|
Non-Operated
|
|
|
Aurora Oil and Gas Limited
|
|
Individual Investor
|
|
Eagle Ford
|
|
Non-Operated
|
|
|
Linn Energy, LLC
|
|
Undisclosed company(ies)
|
|
Bakken
|
|
Operated
|
|
|
Linn Energy, LLC
|
|
Concho Resources Inc. †
|
|
Bakken
|
|
Operated
|
|
|
†
|
Transactions excluded from the high, low, mean, and median ratios summarized below for Enterprise Value/PD Reserves because data was not available for those transactions.
|
⌂
|
Transactions excluded from the high, low, mean, and median ratios summarized below for Enterprise Value/Proved Reserves because data was not available for those transactions.
|
‡
|
Transactions excluded from the high, low, mean, and median ratios summarized below for Enterprise Value/Production because data was not available for those transactions.
|
*
|
Indicates whether or not properties are primarily operated by Seller.
|
Using publicly available information, STRH calculated and analyzed ratios for the Selected Transactions as follows:
●
|
enterprise value divided by proved reserves (on a BOE basis), referred to below as “Enterprise Value/Proved Reserves”;
|
●
|
enterprise value divided PD Reserves (on a BOE basis), referred to below as “Enterprise Value/PD Reserves”; and
|
●
|
enterprise value divided by latest daily production (on a BOEpd basis), referred to below as “Enterprise Value/Production.”
|
The results of the Selected Transactions Analysis are summarized below for all of the Selected Transactions and for the Selected Transactions involving primarily non-operated assets only:
Selected Transactions Ratios (All Selected Transactions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$9.68 |
|
|
$20.63 |
|
|
$18.20 |
|
|
$40.00 |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$13.49 |
|
|
$45.33 |
|
|
$44.13 |
|
|
$88.89 |
|
Enterprise Value/Production ($ / BOEpd)
|
|
$46,937 |
|
|
$103,405 |
|
|
$107,409 |
|
|
$216,667 |
|
Selected Transactions Ratios (Primarily Non-Operated Companies Only):
|
|
|
|
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$9.68 |
|
|
$23.66 |
|
|
$23.21 |
|
|
$40.00 |
|
|
|
$13.49 |
|
|
$42.43 |
|
|
$40.97 |
|
|
$88.89 |
|
|
|
$46,937 |
|
|
$103,832 |
|
|
$108,178 |
|
|
$216,667 |
|
The reasons for and the circumstances surrounding each of the Selected Transactions analyzed were diverse and there are inherent differences between the businesses, operations, financial conditions and prospects of Earthstone, the Oak Valley Subsidiaries and the companies and assets included in the selected transaction analysis. Accordingly, STRH believed that a purely quantitative selected transaction analysis would not be particularly meaningful in the context of considering the exchange. STRH therefore made qualitative judgments concerning differences between the characteristics of the Selected Transactions and the exchange.
Using the reference ranges for the benchmarks set forth below and the corresponding financial or operating statistics for Earthstone as provided by Earthstone management, STRH derived implied equity values for Earthstone also as set forth below (rounded to the nearest one million dollars), compared in each case to Earthstone’s market capitalization as of May 9, 2014 of approximately $37 million and Earthstone’s estimated net asset value (calculated as summarized below) of approximately $46 million:
|
|
|
|
Approximate
Implied Equity Value*
($ in millions)
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$14 per BOE - $22 per BOE
|
|
$39 - $65
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$34 per BOE - $54 per BOE
|
|
$59 - $97
|
Enterprise Value/Production ($ / BOEpd)
|
|
$93,000 per BOEpd - $123,000 per BOEpd
|
|
$50 - $68
|
* Equity value derived as enterprise value minus outstanding net debt.
Using the reference ranges for the benchmarks set forth below and the corresponding financial or operating statistics for the Oak Valley Subsidiaries as provided by Oak Valley’s management and including the $107 million in uncalled equity commitments, STRH derived implied equity values for the Oak Valley Subsidiaries also as set forth below (rounded to the nearest one million dollars), compared to Oak Valley’s estimated net asset value (calculated as summarized below) of approximately $237 million:
|
|
|
|
Approximate
Implied Equity Value*
($ in millions)
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$14 per BOE - $22 per BOE
|
|
$287 - $378
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$34 per BOE - $54 per BOE
|
|
$253 - $327
|
Enterprise Value/Production ($ / BOEpd)
|
|
$93,000 per BOEpd - $123,000 per BOEpd
|
|
$326 - $390
|
* Equity value derived as enterprise value minus outstanding net debt.
STRH estimated the net asset value, or “NAV,” of Earthstone’s PD Reserves on a PV-10 basis, proved developed non-producing oil and gas reserves, or “PDNP” on a PV-10 basis, proved undeveloped oil and gas reserves, or “PUD” on a PV-10 basis, and non-proved acreage, in each case to the assumed end of their economic lives and based on data from the Earthstone Reserve Report and the Earthstone Roll Forward Report. In performing this analysis, STRH applied a risk weighting of 100% to Earthstone’s PD Reserves, 90% to Earthstone’s PDNP, 65% to Earthstone’s PUD, and 55% to Earthstone’s non-proved acreage, which risk weightings were agreed to by Earthstone and Oak Valley managements, respectively. Taking into account Earthstone’s net debt, net working capital and asset retirement obligations, in each case as of December 31, 2013, this resulted in an NAV for Earthstone
(rounded to the nearest one million dollars) of approximately $46 million.
STRH estimated the NAV of the Oak Valley Subsidiaries’ PD Reserves on a PV-10 basis, PDNP on a PV-10 basis, PUD on a PV-10 basis, and non-proved acreage, in each case to the assumed end of their economic lives and based on data from the Oak Valley Reserve Report. In performing this analysis, STRH applied a risk weighting of 100% to the Oak Valley Subsidiaries’ PD Reserves, 90% to Oak Valley’s PDNP, 65% to the Oak Valley Subsidiaries’ PUD, and 53% to the Oak Valley Subsidiaries’ non-proved acreage, which risk weightings were agreed to by Earthstone and Oak Valley managements,
respectively. Taking into account the Oak Valley Subsidiaries’ net debt, net working capital and asset retirement obligations, in each case as of February 28, 2014, this resulted in an NAV for the Oak Valley Subsidiaries (rounded to the nearest one million dollars) of approximately $237 million.
Implied Pro Forma Contribution Analysis
STRH estimated the contribution of each of Earthstone and the Oak Valley Subsidiaries to the pro forma combined company with respect to proved reserves on a PV-10 basis, average daily production, PD Reserves, and PUD, in each case to the assumed end of their economic lives and based on data from the Earthstone Reserve Report, the Earthstone Roll Forward Report, the Oak Valley Reserve Report and information provided by Earthstone management and Oak Valley managements, respectively. This analysis showed the following percentage contributions by each of the Oak Valley Subsidiaries and Earthstone, compared in each case to the pro forma NAV before financial adjustments of approximately 71% by Oak Valley and 29% by Earthstone stockholders as a group:
|
|
|
|
|
|
|
Proved Reserves PV-10
|
|
|
67% |
|
|
|
33% |
|
Average Daily Production
|
|
|
78% |
|
|
|
22% |
|
PD Reserves
|
|
|
66% |
|
|
|
34% |
|
PUD Reserves
|
|
|
78% |
|
|
|
22% |
|
|
|
|
|
|
|
|
|
|
Average of the benchmarks above
|
|
|
72% |
|
|
|
28% |
|
NAV (before financial adjustments)*
|
|
|
71% |
|
|
|
29% |
|
* Before taking into account cash, net working capital, asset retirement obligations and total debt.
Implied Pro Forma Ownership
STRH also estimated the contribution of each of Earthstone and the Oak Valley Subsidiaries to the pro forma combined company with respect to the implied equity values of Earthstone and the Oak Valley Subsidiaries to the pro forma combined company using the implied equity valuations of Earthstone and the Oak
Valley Subsidiaries summarized above using the Selected Company Analysis, Selected Transaction Analysis and the NAV analysis. This analysis showed the following ranges of implied ownership percentages by Earthstone stockholders, calculated by comparing the lowest estimation of Earthstone to the highest estimation of the Oak Valley Subsidiaries and the highest estimation of Earthstone to the lowest estimation of the Oak Valley Subsidiaries, compared in each case to the pro forma share ownership of approximately 16% by Earthstone stockholders as a group:
|
|
|
|
|
Earthstone
Estimated Equity Valuation
($ in millions)
|
|
|
Implied Pro Forma Ownership by Earthstone Stockholders as a Group
|
Selected Company Analysis:
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$264 - $355 |
|
|
$33 - $58 |
|
|
8.4% - 18.1% |
Enterprise Value/PD Reserves ($ / BOE)
|
|
$245 - $319 |
|
|
$55 - $93 |
|
|
14.7% - 27.5% |
Enterprise Value/Production ($ / BOEpd)
|
|
$309 - $373 |
|
|
$45 - $63 |
|
|
10.8% - 16.9% |
Enterprise Value/PV-10
|
|
$240 - $265 |
|
|
$49 - $61 |
|
|
15.6% - 20.3% |
Enterprise Value/2014E EBITDA
|
|
$304 - $339 |
|
|
$36 - $44 |
|
|
9.6% - 12.7% |
Enterprise Value/2015E EBITDA
|
|
$413 - $495 |
|
|
$31 - $42 |
|
|
5.9% - 9.2% |
Selected Transaction Analysis:
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$287 - $378 |
|
|
$39 - $65 |
|
|
9.3% - 18.4% |
Enterprise Value/PD Reserves ($ / BOE)
|
|
$253 - $327 |
|
|
$59 - $97 |
|
|
15.3% - 27.7% |
Enterprise Value/Production ($ / BOEpd)
|
|
$326 - $390 |
|
|
$50 - $68 |
|
|
11.3% - 17.2% |
NAV Analysis:
|
|
|
|
|
|
|
|
|
Net Asset Value
|
|
$213 - $261 |
|
|
$41 - $51 |
|
|
13.7% - 19.2% |
In addition, STRH estimated the contribution of each of Earthstone and the Oak Valley Subsidiaries to the pro forma combined company with respect to the implied equity values of Earthstone and the Oak Valley Subsidiaries to the pro forma combined company using the implied valuations of the Oak Valley Subsidiaries summarized above using the Selected Company Analysis, Selected Transaction Analysis and the NAV analysis and Earthstone’s market capitalization of approximately $37 million as of May 9, 2014 and Earthstone’s estimated NAV of approximately $46 million estimated as described above. This analysis showed
the following ranges of implied ownership percentages by Earthstone stockholders, calculated by comparing Earthstone’s market capitalization of approximately $37 million as of May 9, 2014 to the lowest and highest estimations of the Oak Valley Subsidiaries and Earthstone’s estimated NAV of approximately $46 million to the lowest and highest estimations of the Oak Valley Subsidiaries, compared in each case to the pro forma share ownership of approximately 16% by Earthstone stockholders as a group:
|
|
|
|
|
Implied Pro Forma Ownership by Earthstone Stockholders as a Group (using Earthstone’s market capitalization of approximately $37 million)*
|
|
|
Implied Pro Forma Ownership by Earthstone Stockholders as a Group (using Earthstone’s estimated NAV of approximately $46 million)*
|
|
Selected Company Analysis:
|
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$264 - $355 |
|
|
9.4% - 12.3% |
|
|
|
11.5% - 14.9% |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$245 - $319 |
|
|
10.4% - 13.1% |
|
|
|
12.6% - 15.8% |
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Enterprise Value/ Production ($ / BOEpd)
|
|
$309 - $373 |
|
|
9.0% - 10.7% |
|
|
|
11.0% - 13.0% |
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Enterprise Value/PV-10
|
|
$240 - $265 |
|
|
12.3% - 13.4% |
|
|
|
14.8% - 16.1% |
|
Enterprise Value/2014E EBITDA
|
|
$304 - $339 |
|
|
9.8% - 10.9% |
|
|
|
11.9% - 13.2% |
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Enterprise Value/2015E EBITDA
|
|
$413 - $495 |
|
|
7.0% - 8.2% |
|
|
|
8.5% - 10.0% |
|
Selected Transaction Analysis:
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|
|
|
|
|
|
|
|
|
|
Enterprise Value/Proved Reserves ($ / BOE)
|
|
$287 - $378 |
|
|
8.9% - 11.4% |
|
|
|
10.8% - 13.8% |
|
Enterprise Value/PD Reserves ($ / BOE)
|
|
$253- $327 |
|
|
10.2% - 12.8% |
|
|
|
12.3% - 15.4% |
|
Enterprise Value/Production ($ / BOEpd)
|
|
$326- $390 |
|
|
8.7% - 10.2% |
|
|
|
10.6% - 12.4% |
|
NAV Analysis:
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|
|
|
|
|
|
|
|
|
|
Net Asset Value
|
|
$213 - $261 |
|
|
12.4% - 14.8% |
|
|
|
15.0% - 17.7% |
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* Percentages may not tie due to rounding.
STRH also reviewed and considered other factors, solely for informational purposes, including the 52-week low and high aggregate equity values of Earthstone for the period ended May 9, 2014, which ranged from approximately $22 million to approximately $42 million, respectively. In addition, STRH reviewed the historical VWAP of the Earthstone common stock for the 1-month, 3-month, 6-month and 12-month periods ended May 9, 2014, which indicated the following:
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|
|
|
1-month
|
|
$22.03 |
|
3-month
|
|
$21.01 |
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6-month
|
|
$19.37 |
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12-month
|
|
$18.37 |
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Accounting Treatment
The exchange will be accounted for as a reverse acquisition under the purchase method of accounting under GAAP. Earthstone will be treated as the acquired corporation for accounting and financial reporting purposes. Earthstone’s assets, liabilities and other items will be adjusted to their estimated fair values on the closing date of the exchange and combined with the historical book values of the assets and liabilities of Oak Valley. Applicable income tax effects of these adjustments will be included as a component of the combined company’s deferred tax asset or liability. The difference between the estimated fair value of the assets (including separately identifiable intangible assets), liabilities and other items (adjusted as discussed above) and the purchase price will be recorded as goodwill. Financial statements of Oak Valley issued after the exchange will reflect these values and will not be restated
retroactively to change the historical financial position or results of operations of Earthstone.
Listing of Earthstone Common Stock
Earthstone shares are currently traded on the NYSE MKT under the symbol “ESTE,” and the common stock to be issued to Oak Valley will be listed upon issuance.
No Dissenters’ or Appraisal Rights
Under Delaware law, Earthstone stockholders will not be entitled to dissenters’ or appraisal rights in connection with the transactions contemplated by the exchange agreement or the issuance of Earthstone shares pursuant to the exchange agreement.
Interests of Earthstone Executive Officers and Directors in the Exchange
None of the executive officers of Earthstone have employment contracts. The exchange agreement provides that upon closing of the exchange, the executive officers of Earthstone, other than Mr. Singleton, will no longer remain as executive officers of Earthstone. In connection with its consideration of the exchange agreement, the Earthstone Board adopted the Employee Severance Compensation Plan, which provides severance benefits for employees designated by the Board. If these employees are terminated by Earthstone within one year of a Change of Control (as defined in the Severance Plan), or if an employee terminates his employment for Good Reason (as defined in the Severance Plan) during this period, the employee will receive (i) cash severance compensation equal to a number of weeks of base salary determined based on the employee’s years
of service with Earthstone, with a maximum of fifty-two (52) weeks, and (ii) up to nine (9) months of premiums for continuation coverage under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”). In addition, the Severance Plan provides that all unvested restricted stock held by designated employees vests upon a Change of Control. All of Earthstone’s Denver-based employees have been named participants in the Severance Plan, including Earthstone’s Chief Executive Officer and President, Ray Singleton. Earthstone’s only other executive officer, who is working for Earthstone pursuant to a consulting arrangement, has not been named a participant in the Severance Plan. Mr. Singleton, Chief Executive Officer and President, will continue to be an officer of Earthstone as Executive Vice President – Northern Region, and his employment will continue to be “at will,”
which means either Mr. Singleton or Earthstone can terminate his employment at any time without notice, although Mr. Singleton would be entitled to benefits in accordance with the terms of the Severance Plan. The transactions contemplated by the exchange constitute a Change of Control under the Severance Plan.
In addition, the non-employee directors of Earthstone have received annual grants of restricted stock pursuant to a Director Compensation Plan. Pursuant to the terms of this plan, all shares of restricted stock that are still subject to vesting will vest upon a Change of Control. At the date of the exchange, Earthstone anticipates that directors will own the following number of shares of restricted stock that will vest upon completion of the exchange: Mr. Rogers: 3,678 shares; Mr. Robertson: 3,678 shares; and Mr. Calerich: 3,678 shares.
Interests of Oak Valley Executive Officers and Directors in the Exchange
The Oak Valley executive officers are identified in the section entitled “The Exchange Agreement – Officers of the Combined Company” and “The Exchange Agreement – Proposed Non-Management Directors of the Combined Company” beginning on pages 77 and 78, respectively.
All of the officers of Oak Valley have an equity interest in Oak Valley Management, LLC (“OVM”), which owns 100% of Oak Valley’s Class B Units. In addition, the Oak Valley officers share indirectly in Class C Units held by OVM. As a result, several officers and employees of Oak Valley will become indirect beneficial owners of a portion of the Earthstone common stock to be issued in the exchange, and may become record owners of Earthstone shares if Earthstone shares are distributed by Oak Valley to its members. The amounts attributable to specific officers and directors of Oak Valley or the combined company cannot presently be determined because of various allocation provisions in the Oak Valley operating agreement.
Compensation of Non-Management Directors After the Exchange
Earthstone currently pays each non-employee director an annual cash retainer of $16,000, together with $2,000 for attending each regular quarterly meeting of the Earthstone Board and each all-day special meeting of the Earthstone Board and $500 for each half-day special meeting of the Earthstone Board or one of its committees. In addition to cash compensation, each non-employee director receives annual stock-based compensation in the amount of $36,000 in the form of restricted stock. The shares of restricted stock vest one-third on each anniversary date commencing on the first anniversary of the date of issuance. No committee fees are payable for attendance by a director at a committee meeting held in conjunction with a regular quarterly or all-day special meeting of the Earthstone Board. The chairman of each of the Audit, Compensation and Nominating Committees receives an annual cash retainer of $5,500, $4,500 and $3,500,
respectively. In addition, non-employee directors receive $500 for attending committee meetings, unless the committee meeting is held in conjunction with a quarterly regular or all-day board meeting. Earthstone also reimburses reasonable expenses incurred by non-employee directors associated with attending board and committee meetings.
Oak Valley currently contemplates that, upon consummation of the exchange, six nominees of Oak Valley will be appointed to Earthstone’s Board. Class I directors, who will serve until the 2016 annual meeting, will be Ray Singleton and Frank A. Lodzinski. Class II directors, who will serve until the 2014 annual meeting, will be Douglas E. Swanson, Brad A. Thielemann and Zachary G. Urban, Jr. Class III directors, who will serve until the 2015 annual meeting will be Jay F. Joliat and Robert L. Zorich. Non-employee directors, which excludes Messrs. Lodzinski and Singleton, will each receive fees from Earthstone for being a director and committee member as follows:
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an annual retainer of $20,000;
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an additional $8,000 per year to the chair of the audit committee;
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an additional $4,000 per year to the other audit committee member; and
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$1,000 per meeting attended.
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Fees will be paid quarterly and all reasonable travel, lodging and other expenses will be reimbursed. Directors employed by Earthstone will receive no compensation for board service.
THE EXCHANGE AGREEMENT
This section of this proxy statement is a summary of the material provisions of the exchange agreement, a copy of which is attached to this proxy statement as Annex A. The provisions of the exchange agreement are complicated and not easily summarized. Because the description is a summary, it does not contain all of the information about the exchange agreement that may be important to you. You should refer to the full text of the exchange agreement, which is hereby incorporated by reference into this proxy statement, for details of the exchange and the terms and conditions of the exchange agreement.
Earthstone and Oak Valley entered into the exchange agreement dated May 15, 2014. The exchange agreement provides that, upon the terms and subject to the conditions set forth in the exchange agreement, Oak Valley will contribute to Earthstone the membership interests of its three subsidiaries, Oak Valley Operating, LLC, EF Non-Op, LLC and Sabine River Energy, LLC, which include an estimated $142.5 million of cash, in exchange for the issuance to Oak Valley of approximately 9.12 million shares of Earthstone common stock (the “exchange”). The specified amount of cash represents existing cash on hand plus approximately $107 million of capital commitments available to Oak Valley from its members in accordance with the terms of its limited liability company agreement. Following the exchange,
current Earthstone stockholders will own 16% of Earthstone’s outstanding common stock, and Oak Valley will own 84% of Earthstone’s outstanding common stock.
Completion and Effectiveness of the Exchange
The parties will complete the transactions contemplated in the exchange agreement when all of the conditions to completion of the transactions, as contained in the exchange agreement, are satisfied or waived. The parties anticipate closing the transactions as soon as possible after approval by the Earthstone stockholders of the proposals set forth in this proxy statement.
Representations and Warranties
The exchange agreement contains mutual representations and warranties made by each of Earthstone and Oak Valley regarding aspects of their respective businesses, financial condition and structure, as well as other facts pertinent to the exchange. These representations and warranties are made only as of the date of the exchange agreement and the closing date, are subject to materiality, knowledge and other similar qualifications in many respects and will not survive after closing.
Representations are generally parallel from each of Oak Valley and Earthstone, except that the Oak Valley representations extend to the Oak Valley Subsidiaries and deal generally with such matters as the following:
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due organization, organizational power, and qualification to do business;
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capitalization and due authorization of outstanding equity;
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authorization of the exchange agreement and related agreements;
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non-contravention of the exchange agreement with organizational documents and material agreements;
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absence of required consents or governmental filings in connection with the exchange agreement;
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accuracy of financial statements;
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absence of liabilities other than those disclosed in the financial statements;
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●
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absence of material changes after latest unaudited financial statements;
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●
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legal title to owned oil and gas properties, validity of and absence of default under leases to leased oil and gas properties, full payment of all royalties and rents;
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●
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all tax returns filed and no liability for unpaid taxes;
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●
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absence of material legal or environmental proceedings;
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●
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absence of preferential rights with respect to properties;
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●
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compliance with employment laws;
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●
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conduct of operations in compliance with applicable laws;
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●
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accuracy of information provided to reserve engineer;
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●
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accuracy of information filed with the SEC and compliance with securities laws;
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compliance of benefit plans with ERISA.
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In addition, Earthstone makes certain representations regarding the shares of Earthstone common stock being issued, and Oak Valley makes certain representations regarding its status as an accredited investor buying restricted shares in an offering exempt from the registration requirements of the Securities Act.
The full text of the representations and warranties can be reviewed in Articles III and IV of the exchange agreement.
Conduct of Parties Pending Closing
As set forth in Section 5.2 of the exchange agreement, each party has agreed that until the closing, without the written consent of the other party, which may not be unreasonably withheld, delayed or conditioned, it will conduct its operations only in the ordinary course consistent with past practices, maintain its business and preserve the goodwill of its customers, suppliers and employees, and comply with all laws and contractual obligations. In particular, the parties have agreed not to, except as disclosed in each party’s respective disclosure schedules to the exchange agreement:
●
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issue or redeem equity or declare dividends;
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●
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issue notes or other debt securities or enter into borrowing agreements or other financing arrangements, other than (i) the credit agreement to be entered by the combined company at the time of the exchange agreement, (ii) borrowings under each party’s credit agreement as in existence at the time of the execution of the exchange agreement, (iii) intercompany borrowings between Oak Valley and Earthstone, or prepay any outstanding borrowings except under existing revolving indebtedness or intercompany indebtedness;
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●
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sell or otherwise dispose of any oil and gas properties having fair market values in excess of, for Earthstone, $1 million, and, for Oak Valley, $12.5 million;
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●
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make capital expenditures in excess of, for Earthstone, $5 million, and for Oak Valley, $20 million;
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●
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make any loans to any person;
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●
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acquire, in the case of Earthstone, any business or assets having a purchase price exceeding $1 million;
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●
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enter into, terminate or amend any material agreement, enter into any agreement with restrictions on the place where a party can do business, or waive any provision of any standstill or confidentiality agreement;
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●
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increase the compensation of any executives, grant any new equity awards or adopt new equity compensation plans;
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●
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amend their formation documents; or
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●
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settle any litigation for payments in excess of, for Earthstone, $50,000 individually or $200,000 in the aggregate and, for Oak Valley, $250,000 individually and $1 million in the aggregate.
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Oak Valley is permitted to make acquisitions between the date of the exchange agreement and closing, subject to the limitations set forth in the exchange agreement, and acquisitions made by Oak Valley could affect the percentage of the combined company owned by Earthstone stockholders after the closing, as well as the make-up of assets of the combined company. Oak Valley may make acquisitions with cash, Earthstone common stock (which acquisitions would close after the closing of the exchange), Oak Valley equity interests, or a combination of these forms of consideration. The acquired assets or entities would become part of the combined company, either by contribution to the Oak Valley Subsidiaries or to Earthstone. Acquisitions may not be made after this proxy statement has been cleared by the SEC. If the consideration in an Oak Valley
acquisition is cash, the amount of cash that Oak Valley contributes to the Oak Valley Subsidiaries prior to the closing would be reduced, but that contribution cannot be less than $75 million. If the consideration in an Oak Valley acquisition is Earthstone common stock, the percentage of the combined company owned by the Earthstone stockholders would be reduced, but Oak Valley may not agree to issue a number of shares that would make the percentage ownership of Earthstone stockholders be less than 12%. Any acquisition by Oak Valley would not result in Earthstone issuing less than 9,124,452 shares to Oak Valley, subject to reduction if Oak Valley’s members fail to fund the full $107 million capital call. If Oak Valley consummates an acquisition using its own equity comprised of LLC units, the number of shares of Earthstone common stock would be increased by a number of shares of
common stock equal to the LLC unit portion of the purchase price divided by 25.98.
See Section 5.2 of the exchange agreement for the list of activities that the parties are prohibited from engaging in prior to closing.
Included among the obligations of the parties are the following:
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Earthstone is obligated to file this proxy statement with the SEC and give notice of and convene a special meeting of the stockholders as provided in this proxy statement to approve the issuance of the common stock included in the exchange consideration, approve the amendment to Earthstone’s certificate of incorporation and approve and adopt the 2014 Plan.
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●
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Earthstone and Oak Valley shall use commercially reasonable efforts to consummate the closing of the exchange.
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Earthstone shall not (i) solicit, facilitate, encourage or induce any inquiries or proposals that constitute the submission of an alternative exchange or merger proposal with a person or entity other than Oak Valley, (ii) furnish confidential information, (iii) enter into any confidentiality agreement or agreement relating to an alternative proposal, or (iv) withdraw or modify the recommendation to vote for the matters put forth to stockholders for vote (other than the non-binding advisory proposal involving the Severance Plan).
Earthstone’s non-solicitation obligations are qualified by “fiduciary out” provisions which provide that Earthstone may take certain otherwise prohibited actions with respect to an unsolicited alternative proposal if the Board determines that the failure to take such action would be reasonably likely to be inconsistent with its fiduciary duties and certain other requirements are satisfied. Earthstone may provide confidential information to and negotiate with any person who gives Earthstone an alternative proposal without Earthstone having violated the “no shop” provisions of the exchange agreement. If the alternate proposal is superior to the consideration in the Oak Valley combination, Earthstone shall promptly advise Oak Valley of any alternative proposal. Earthstone may recommend to its stockholders that it accept the alternative proposal under circumstances set forth in Section 5.3 of the exchange agreement.
In particular, if at any time prior to the approval of the exchange agreement by Earthstone stockholders Earthstone’s Board of Directors receives an alternative proposal from a third party to acquire at least 50% of Earthstone’s outstanding common stock or assets and that (i) the Board deems to be bona fide and (ii) the Board determines to be more favorable to the Earthstone stockholders from a financial point of view than the transactions contemplated by the exchange agreement (a “Superior Proposal”), then the Board may reverse its recommendation that the Earthstone stockholders approve the exchange agreement and may enter into negotiations and execute a definitive agreement with respect to the Superior Proposal, subject to (x) providing three business days’ notice to Oak Valley of the Superior Proposal and (y) at Oak Valley’s request, negotiating in good with faith with Oak Valley during such three business day period in connection with
an alternative transaction.
A termination fee of $1.0 million will be payable by Earthstone in the following circumstances:
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(A) an alternate proposal has been publicly proposed and not withdrawn at the date of the stockholder meeting, (B) Oak Valley terminates the exchange agreement because (1) the exchange has not occurred by November 30, 2014, or (2) Earthstone stockholders do not approve the matters proposed in this proxy statement (other than the non-binding advisory proposal involving the Severance Plan), and (C) Earthstone enters into an agreement with respect to, or consummates a transaction that constitutes, an “Alternative Proposal” (except that references to 20% shall be deemed references to 50%);
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●
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the exchange agreement is terminated by Oak Valley if the Earthstone Board changes its recommendation that the Earthstone stockholders vote in favor of the matters proposed in this proxy statement (other than the non-binding advisory proposal involving the Severance Plan); or
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the exchange agreement is terminated by Earthstone in order to accept a Superior Proposal.
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Capital Call. Oak Valley is required to make a capital call of its members for $107,020,000, the amount of which is to be used to make acquisitions by Oak Valley as permitted by the exchange agreement (which assets would be included in the Oak Valley Subsidiaries) or contributed to the Oak Valley Subsidiaries prior to the exchange. To the extent that members fail to fully fund the capital call (the “Cash Shortfall”), Earthstone shall reduce the number of shares of common stock issued to Oak Valley by a number of shares equal to the Cash Shortfall divided by 25.98. No less than $100,000,000 is required to be contributed (or spent on qualifying acquisitions).
Indemnification and Insurance. Following the exchange, Earthstone will be responsible for indemnifying officers, directors and employees of the Oak Valley Subsidiaries to the extent that such persons were subject to indemnification prior to the exchange. For six years following the closing of the exchange, the formation documents of the Oak Valley Subsidiaries shall be no less favorable with respect to indemnification, advancement of expenses and exculpation of present and former officers, directors and employees than those in effect immediately prior to the exchange, and during such period Earthstone shall not amend its charter documents to make them less favorable with respect to these matters than those currently in effect.
Earthstone shall purchase six years of “tail insurance” to provide for indemnification of existing Earthstone directors, officers and employees for acts committed prior to the date of the exchange.
Governance. For two years after the closing of the exchange, Oak Valley will not use its controlling stockholder position to undertake or initiate a “going private” transaction with respect to Earthstone.
Credit Agreement. Oak Valley and Earthstone will use commercially reasonable best efforts to enter into a new reserve-based revolving credit facility substantially in the form of Oak Valley’s existing credit facility. Amounts borrowed at the closing will be sufficient to repay at closing all outstanding borrowings under the existing credit facilities of each of Earthstone and Oak Valley.
Hedges. Earthstone will become the responsible party on all of Oak Valley’s hedges at the time of the exchange. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Oak Valley” for a description of Oak Valley hedges.
Conditions to the completion of the exchange, as set forth in the exchange agreement, include the following:
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Approval by the Earthstone stockholders of the issuance of common stock as provided in the exchange agreement, the amendment to the certificate of incorporation increasing the authorized shares of Earthstone capital stock, and the 2014 Plan.
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●
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The Earthstone common stock deliverable to Oak Valley as contemplated by the exchange agreement shall have been approved for listing on the NYSE MKT, subject to official notice of issuance.
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●
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All representations and warranties of the parties shall be true and correct as of the closing date, except where the failure to be true and correct would not reasonably be expected to have, individually or in the aggregate, a material adverse effect.
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●
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The parties will have performed, in all material respects, all obligations required by the exchange agreement.
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Oak Valley shall provide evidence that it has received at least $100,000,000 from its members and shall have (i) contributed such amounts to the Oak Valley Subsidiaries on or prior to the closing date, or (ii) used such amounts to consummate permitted Oak Valley interim acquisitions.
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At closing, all directors and officers of Earthstone, except for Ray Singleton, shall resign, and Mr. Singleton shall elect six nominees of Oak Valley as directors of Earthstone. The newly elected directors shall serve for a one, two or three year term, depending on the class to which they are assigned. The Earthstone Board, as then constituted, shall appoint the appropriate officers of Earthstone, including Mr. Singleton as an Executive Vice President – Northern Region. At closing, Earthstone shall be appointed as the managing member of each Oak Valley Subsidiary.
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Termination of the Exchange Agreement
The exchange agreement may be terminated for reasons that include the following:
●
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By the mutual written consent of the Oak Valley board of managers and the Earthstone Board of Directors.
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●
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By either party if the exchange has not been completed by November 30, 2014, although the exchange agreement may not be terminated by any party that is unable to satisfy any closing condition, or by any party if specific performance to enforce the exchange agreement is being pursued. In addition, the right to terminate shall not be available to Oak Valley until December 31, 2014 if Oak Valley has not yet received at least $100,000,000 from its members and Oak Valley is then pursuing and has not yet exhausted its remedies under its limited liability company agreement. If Oak Valley then terminates because Oak Valley has not received at least $100,000,000 from its members, Oak Valley shall, as a condition of such termination, pay to Earthstone an amount equal to Earthstone’s documented, out-of-pocket expenses incurred in connection
with the exchange agreement in an amount not to exceed $600,000.
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●
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By either party if the Earthstone stockholder meeting has concluded and the Earthstone stockholder approval has not been obtained.
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By either party if any applicable law, injunction, judgment or ruling enacted, promulgated, issued, entered, amended or enforced shall be in effect enjoining, restraining, preventing or prohibiting or rendering illegal consummation of the exchange.
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By either party if the representations and warranties of the other party are not true and correct, any condition would not be satisfied, or any party fails to meet its obligations under the exchange agreement, and the breach either cannot be cured or can be cured and is not cured within 30 days after notice.
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By Oak Valley prior to the receipt of Earthstone stockholder approval if Earthstone willfully breached its obligations not to solicit any inquiries or proposals that constitute the submission of an alternative exchange or merger proposal or enters into any agreement relating to an alternative proposal.
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By Earthstone if its Board, in the reasonable exercise of its fiduciary duties, decides to accept a superior proposal, as defined in the exchange agreement.
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By Oak Valley if Earthstone withdraws, modifies or qualifies, or proposes publicly to withdraw, modify or qualify, in a manner adverse to Oak Valley, the Earthstone Board recommendation to vote for the resolutions set forth in this proxy statement (other than the non-binding advisory proposal involving the Severance Plan) or publicly recommends the approval or adoption of, or publicly approves or adopts, or proposes to publicly recommend, approve or adopt, any alternative proposal.
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In connection with the execution of the exchange agreement, Ray Singleton, Earthstone’s President and Chief Executive Officer and holder of approximately 26% of Earthstone’s outstanding common stock, entered into a voting agreement with Oak Valley whereby Mr. Singleton agreed to vote in favor of the exchange and the related matters, unless the exchange agreement is terminated according to its terms prior to the stockholder meeting.
At the closing of the exchange, Oak Valley and Earthstone will enter into a registration rights agreement requiring Earthstone to register, at its cost, with the SEC the resale of the shares issued to Oak Valley at the request of Oak Valley or a member of Oak Valley that has received the shares in a distribution from Oak Valley (collectively, the “Oak Valley Stockholders”). The Oak Valley Stockholders owning a majority of the Registrable Securities (as defined in the registration rights agreement) may request registration no more than three times, and no more frequently than once in any six-month period, of shares having an estimated offering price of greater than $5 million. No request may be made after the third anniversary of the exchange.
With certain exceptions, Earthstone must file and have the registration statement declared effective, and must maintain the effectiveness of the registration statement for nine months or such shorter period by which all shares have been sold.
In addition, if Earthstone files a registration statement within three years of the exchange, it must offer to the Oak Valley Stockholders the opportunity to include the resale of their shares in the registration statement, subject to customary qualifications and limitations.
Earthstone is prohibited from entering into any other registration rights agreements or other agreement that violates or is detrimental to rights granted to Oak Valley Stockholders in the registration rights agreement.
Except for STRH, the fees and expenses of which will be paid solely by Earthstone, neither Earthstone nor any of its affiliates has retained any financial advisor, broker, agent or finder or paid or agreed to pay any financial advisor, broker, agent or finder on account of the exchange agreement or any transaction contemplated by the exchange agreement.
Officers of the Combined Company
Concurrently with the closing of the exchange, the following individuals will be appointed to fill the following officer positions of Earthstone:
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64 |
|
President and Chief Executive Officer
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|
|
63 |
|
Executive Vice President, Northern Region
|
Robert J. Anderson
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52 |
|
Executive Vice President, Corporate Development and Engineering
|
Steven C. Collins
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|
49 |
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Executive Vice President, Completions and Operations
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Christopher E. Cottrell
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|
54 |
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Executive Vice President, Land and Marketing
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Timothy D. Merrifield
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58 |
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Executive Vice President, Geology and Geophysics
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Francis M. Mury
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62 |
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Executive Vice President, Drilling and Development
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G. Bret Wonson
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36 |
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Vice President, Principal Accounting Officer
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Neil K. Cohen
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32 |
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Vice President, Finance
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Earthstone will re-evaluate its executive compensation structures and systems that it will provide for its named executive offices, with attention to instituting equity awards under the 2014 Plan, if approved, benchmarking compensation based on the knowledge and experience of its board of directors, considering similar positions in the industry and using compensation surveys and the advice of outside consultants, as deemed necessary.
Messrs. Singleton and Lodzinski will serve as Class I directors of Earthstone. Messrs. Swanson, Thielemann and Urban will be appointed to serve as Class II directors, and Messrs. Joliat and Zorich will be appointed to serve as Class III directors.
See “Executive Officers of Oak Valley” for biographical information of Messrs. Lodzinski, Anderson, Collins, Cottrell, Merrifield, Mury, Wonson and Cohen.
Information on Mr. Singleton is as follows:
Ray Singleton has been a director of Earthstone since July 1989 and President and Chief Executive Officer of Earthstone since March 1993. Mr. Singleton was retained by Earthstone from 1981 to 1987 as a consultant. He joined Earthstone in June 1988 as Production Manager/Petroleum Engineer. In October 1989, he was elected Vice President. Mr. Singleton began his career with Amoco Production Company in 1973 as a production engineer in Texas. He was subsequently employed by the predecessor of Union Pacific Resources as a drilling, completion and production engineer from 1980 to 1982. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1973, and received a Master’s Degree in Business Administration from Colorado State University’s Executive MBA Program in 1992.
In determining Mr. Singleton’s qualifications to serve on the Board of Directors, the Board has considered, among other things, his experience and expertise in the oil and gas industry, including the operating, management or executive positions he has held with Earthstone and other oil and gas companies, and his extensive knowledge of Earthstone’s business, all of which has proven to be beneficial to Earthstone.
Proposed Non-Management Directors of the Combined Company
Information on the proposed non-management directors is as follows:
Jay F. Joliat (age 57) – For more than the past thirty years, Mr. Joliat has been an independent investor and developer in commercial, industrial and garden style apartment real estate, land development and residential home building, restaurant ownership and management, and has had extensive experience in placement of venture private equity in generic pharmaceuticals, medical devices/procedures and oil and gas. Mr. Joliat has been the Chief Executive Officer of Fieldstone Village Development, LLC since January 2011. He has been the Chief Executive Officer of Joliat & Company, Inc. since October 1988. He has been the Chief Executive Officer and Chief Investment Officer of Joliat Ventures, LLC and Chief Executive Officer of Joliat Enterprises, LLC since January 1988. Since January 1981, Mr. Joliat has served as Chief Executive Officer and Treasurer of Sign of the Beefcarver Restaurants, Inc. He formed
and managed his own investment management company early in his career and was formerly employed by E.F. Hutton, Dean Witter Reynolds and LPL Financial. He holds a Bachelor of Arts Degree in Management and Finance from Oakland University (1982) and was awarded a Certified Investment Management Analyst certificate in 1983 after completion of the IMCA program at the Wharton School of the University of Pennsylvania. From 1996 through 2003, Mr. Joliat served on the Board of Directors of Caraco Pharmaceutical Laboratories Ltd., a company with a class of equity securities registered under the Exchange Act, and served in various capacities on its audit, executive and compensation committees. From 2007 through August 2012, Mr. Joliat served on the Board of Directors of GeoResources, Inc., a company with a class of equity securities registered under the Exchange Act, and served in various capacities on the audit, nominating and compensation committees. Mr. Joliat’s prior business
experience in management and investments, as well as previously serving on the boards of directors of SEC-reporting companies, brings a unique perspective as an outside investor in oil and gas entities. His management skills, understanding of public and private capital markets, and financial acumen provide the board with a valuable resource for planning corporate strategy.
Douglas E. Swanson, Jr. (age 42) – Partner, EnCap Investments L.P. Prior to joining EnCap in 1999, he was in the corporate lending division of Frost National Bank, specializing in energy-related service companies, and was a financial analyst in the corporate lending group of Southwest Bank of Texas. Mr. Swanson serves on the board of each of Eclipse Resources Corporation, Oasis Petroleum Inc. and several EnCap portfolio companies. Mr. Swanson is a member of the Independent Petroleum Association of America and the Texas Independent Producers and Royalty Owners Association. Mr. Swanson holds a B.A. in Economics and an M.B.A., both from the University of Texas at Austin. Oak Valley believes that Mr. Swanson should serve as a member of the board due to his extensive experience in the oil and gas exploration and production industry, including serving on the boards of public and private oil and gas companies.
As a partner at EnCap, Mr. Swanson is uniquely positioned to provide the board with insight and advice on a full range of strategic, financial, and governance matters.
Brad A. Thielemann (age 37) – Managing Director, EnCap Investments L.P. Prior to joining EnCap in 2006, he worked in the Investor Relations and Strategic Planning Groups at Plains All American Pipeline, L.P. Prior to that, he was an Associate at EnCap from 2000 to 2003 and a Treasury Analyst at Dynegy. Mr. Thielemann holds an M.B.A. from Duke University and a B.A. in Business Administration from The University of Texas at Austin. He serves on the boards of several EnCap portfolio companies, is on the board of The Houston Producers’ Forum and is a member of the Independent Petroleum Association of America. Oak Valley believes that Mr. Thielemann should serve as a member of the board due to his extensive experience in the oil and gas industry, including serving on the boards of private oil and gas exploration and production companies. As a managing director at EnCap, Mr. Thielemann is
uniquely positioned to provide the board with insight and advice on a full range of strategic, financial, and governance matters.
Zachary G. Urban (age 36) – Since January 2014, Mr. Urban has served as CEO at Vlasic Group, which is a private investment company with holdings in a wide variety of asset classes. Prior to being named CEO, Mr. Urban held the position of Managing Director of Investments at Vlasic Group from 2011 to 2013. At Vlasic Group, Mr. Urban has responsibility for a full spectrum of investment disciplines, including asset allocation, investment strategy, direct investments, manager selection, due diligence, and performance measurement. From 2001 to 2011, Mr. Urban worked at Donnelly Penman & Partners (“DP&P”), a regional investment bank. At DP&P, Mr. Urban specialized in merger and acquisition transactions, business valuations, financial advisory, due diligence services, and capital raising for middle market public and private clients. Prior to his time at DP&P, Mr. Urban also worked in
the Corporate Value Consulting practice of PricewaterhouseCoopers LLP (“PWC”). At PWC, he focused on business valuation services, strategic consulting, and corporate finance consulting for public and private companies, including multinational and Fortune 500 clients. Mr. Urban holds the Chartered Financial Analyst (CFA) designation and graduated from the Honors College of Michigan State University with a B.A. degree in Finance with High Honor. Oak Valley believes that Mr. Urban should serve as a member of the board due to his extensive investment experience across diverse industries as CEO of the Vlasic Group. In addition, his prior experience as an investment banker will enable Mr. Urban to provide the board with insight and advice on a full range of general business and financial matters.
Robert L. Zorich (age 64) – Co-Founder and Managing Partner of EnCap Investments L.P. since 1988. Prior to co-founding EnCap, Mr. Zorich was a Senior Vice President of Trust Company of the West, a privately-held pension fund management company, where he was in charge of its Houston office. Prior to joining Trust Company of the West, Mr. Zorich co-founded MAZE Exploration, Inc., an oil and gas exploration, development and reserve acquisition company, where he served as its Co-Chief Executive Officer. During the first seven years of Mr. Zorich’s career, he was a Vice President and Division Manager in the Energy Department of Republic Bank. Approximately half of his tenure with Republic Bank was spent managing Republic Bank’s energy office in London, where he assembled a number of major project financings for development in the North Sea. Mr. Zorich holds a B.A. in Economics from the University of California
at Santa Barbara and a Master’s Degree in International Management (with distinction) in 1974 from the American Graduate School of International Management in Phoenix, Arizona. Mr. Zorich serves on the boards of several EnCap portfolio companies and is a member of the Independent Petroleum Association of America, the Houston Producers’ Forum and Texas Independent Producers and Royalty Owners Association. Mr. Zorich currently serves on the board of Eclipse Resources Corporation and previously served on the board of Oasis Petroleum Inc. and its predecessor entities, Enerplus Corporation and TODCO. Oak Valley believes that Mr. Zorich should serve as a member of the board due to his significant experience with financing, forming, and guiding numerous oil and gas companies while serving as a co-founder and managing partner of EnCap. His insights and relationships should prove valuable towards guiding corporate strategies and pursuing growth opportunities.
U.S. FEDERAL INCOME TAX CONSEQUENCES
Neither Earthstone nor its stockholders will incur any federal income tax consequences as a result of the exchange and other transactions contemplated in the exchange agreement.
INFORMATION CONCERNING THE EARTHSTONE BOARD OF DIRECTORS
The Earthstone Board currently has four members: Ray Singleton (Chairman), Richard K. Rodgers, Monroe W. Robertson, and Andrew P. Calerich. During the year ended March 31, 2014, the Earthstone Board held 12 meetings and acted one time by unanimous written consent in lieu of holding a meeting. Each director attended at least 75% of the total number of meetings and at least 75% of the total number of meetings held by all committees of the Board on which he served.
All members of the Board are encouraged, but not required, to attend Earthstone’s Annual Meeting. All members of the Board attended the most recent annual meeting held on September 25, 2013.
Independence of Directors
Earthstone’s Board must currently satisfy the independence requirements of the NYSE MKT.
Pursuant to SEC and NYSE MKT rules, in determining whether or not a director or nominee for director is independent, Earthstone uses the applicable definition of “independent director” as a non-employee director who is affirmatively determined by the Board not to have a material relationship with the listed company that would interfere with the exercise of independent judgment.
The NYSE MKT LLC Company Guide provides that a majority of the members of the board of directors of each listed company be independent directors, subject to certain limited exceptions. The Board of Directors of Earthstone has determined that three of its four directors are independent directors. Each of Messrs. Rodgers, Robertson, and Calerich is an independent director. In making these determinations, the Board reviewed and analyzed information pertaining to relationships and transactions involving directors, their affiliates and immediate family members to determine whether any of these were of substance and inconsistent with a determination that each director is independent for purposes of serving on the Board of Directors. Ray Singleton, as President and Chief Executive Officer of Earthstone, is not an independent director and thus does not serve
as a member of any committee of the Board. Mr. Singleton currently serves as the Chairman of the Board.
Following the exchange, Earthstone will be a “controlled company” under the corporate governance rules of the NYSE MKT and, as a result, will not be required to comply with the NYSE MKT requirements that independent directors constitute a majority of the board of directors, nominating committee or compensation committee. However, as a “smaller reporting company,” as such term is defined under the Exchange Act, and in accordance with applicable rules and regulations of the NYSE MKT, Earthstone is required to have an audit committee consisting of two independent members. Except for Mr. Singleton, all of the persons serving as director following the exchange will have been selected by Oak Valley. The Earthstone directors after the exchange are expected to be Ray Singleton (Class I director), Frank
A. Lodzinski (Class I director), Douglas E. Swanson, Jr. (Class II director), Brad A. Thielemann (Class II director), Zachary G. Urban (Class II director), Jay F. Joliat (Class III director) and Robert L. Zorich (Class III director). After the exchange, the Earthstone Audit Committee is expected to be comprised of Mr. Joliat (as chairman of the committee) and Mr. Urban.
The standing committees of the Board include the Audit Committee, the Nominating Committee and the Compensation Committee, each consisting entirely of non-employee independent directors. The standing committees of the Board, including the members of each committee, are described below.
Audit Committee – Richard Rodgers, Monroe Robertson, and Andrew Calerich comprise the Audit Committee. Mr. Robertson serves as the Audit Committee’s chairman. The Audit Committee held four meetings in the fiscal year ended March 31, 2014. Each member of the Audit Committee meets the independence and experience requirements, as set forth in the NYSE MKT LLC Company Guide. The Audit Committee engages Earthstone’s independent certified public accountants to audit the annual financial statements, discusses with the auditors and approves in advance the scope of the audit, reviews with the independent auditors their independence, the financial statements and their audit report, reviews management’s administration of the system of internal accounting controls, and reviews Earthstone’s procedures relating to business ethics. The Audit Committee charter is available
on the Earthstone website, www.EarthstoneEnergy.com, under the heading “Investor Relations/Corporate Governance.”
The Board determined that both Messrs. Robertson and Calerich, two of the independent directors, qualify as “financial experts,” as defined in the rules promulgated by the SEC and as set forth in the NYSE MKT LLC Company Guide, to serve on the Audit Committee.
Nominating Committee – The Nominating Committee is comprised of Messrs. Rodgers, Robertson, and Calerich. Mr. Calerich currently serves as the Nominating Committee’s chairman. Each member of the Nominating Committee meets the independence requirements, as set forth in the NYSE MKT LLC Company Guide described above. The Nominating Committee held one meeting in the fiscal year ended March 31, 2014. The Nominating Committee is appointed by the Board to identify individuals qualified to become members of the Board, to recommend to the Board proposed nominees for membership, and to recommend directors to serve on each standing committee. The Nominating Committee charter is available on the Earthstone website, www.EarthstoneEnergy.com,
under the heading “Investor Relations/Corporate Governance.”
Compensation Committee – The Compensation Committee is comprised of Messrs. Rodgers and Robertson. Mr. Rodgers serves as the Compensation Committee’s chairman. Each member of the Compensation Committee meets the independence requirements, as set forth in the NYSE MKT LLC Company Guide. The Compensation Committee held one meeting in the fiscal year ended March 31, 2014. The responsibilities of the Compensation Committee are three-fold: first, establishing and administering the general compensation policies of Earthstone; second, setting the specific compensation for Earthstone’s chief executive officer and other executive officers; and third, recommending to the Board the independent director compensation. The Compensation Committee charter is available on the Earthstone website,
www.EarthstoneEnergy.com, under the heading “Investor Relations/Corporate Governance.”
Code of Business Conduct and Ethics – Earthstone adopted a Code of Business Conduct and Ethics (as that term is defined in Item 406 of Regulation S-K), which applies to its directors, officers and employees, including, without limitation, the principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. The text of the Code of Ethics can be found on Earthstone’s website, www.EarthstoneEnergy.com, under the heading “Investor Relations/Corporate Governance.”
Certain Relationships and Related Transactions
Other than the transactions described herein pursuant to the exchange agreement, there are no transactions or series of similar transactions since the beginning of Earthstone’s last fiscal year or any currently proposed transaction or series of similar transactions to which Earthstone was or is to be a party, and which involved an amount exceeding $60,000 and in which any director, executive officer, principal stockholder or any member of their immediate family had or will have a direct or indirect material interest.
Earthstone is not aware of any legal proceedings in which any director, officer or any record or beneficial owner of more than five percent of any class of Earthstone’s voting securities, or any affiliate of such person, is a party adverse to Earthstone or has a material interest adverse to Earthstone.
INFORMATION ABOUT OAK VALLEY
Oak Valley Resources, LLC (“Oak Valley”), through its three subsidiaries, is an independent domestic oil and natural gas company focused on the acquisition, development, exploration and production of onshore, unconventional reserves. Its current emphasis is on developing its existing proven acreage in the Eagle Ford shale in South Texas. As of December 31, 2013, Oak Valley has accumulated approximately 74,300 gross / 17,500 net leasehold acres in the Eagle Ford trend, consisting of (a) 48,000 gross / 14,400 net leasehold acres located in the volatile oil window in Gonzales and Fayette Counties, Texas, and (b) 26,300 gross / 3,100 net leasehold acres located in the gas and condensate window in La Salle County, Texas.
Oak Valley serves as the operator of its Fayette County and Gonzales County acreage with working interests ranging from 25% to 30% and as a non-operator on its La Salle County acreage with working interests ranging from 10% to 15%. On Oak Valley’s operated acreage, it is presently concentrated on the horizontal development of the Eagle Ford formation, with the Austin Chalk formation serving as a secondary objective. The acreage position is also prospective for the Upper Eagle Ford, Buda, Wilcox, and Edwards formations. Oak Valley is continuously evaluating opportunities to expand its acreage positions and its producing assets in unconventional properties via acquisitions and leasing activities. In the future, it may also consider acquiring and developing conventional properties, provided that such properties have a strategic benefit.
Oak Valley was initially capitalized on December 21, 2012, with producing properties, acreage, working capital, and $100 million of cash commitments from affiliates of EnCap Investments L.P. and approximately $52 million of cash commitments from management and employees of Oak Valley, an affiliate of Wells Fargo Energy Capital, and the Vlasic Group. On April 25, 2013, Oak Valley closed a private placement of approximately $63 million of cash commitments from accredited investors. Many of these investors have participated with Oak Valley management in prior entities. In total, Oak Valley raised approximately $215 million of cash commitments, of which $108 million has been invested to date in oil and gas projects. Concurrent with the closing of the exchange, Oak
Valley will call the remaining $107 million and contribute this amount to Earthstone.
Oak Valley’s core competencies include (a) in-depth experience and capability of its geological and geophysical staff, particularly in the use of 3-D seismic data, (b) proven capability of its engineering staff to minimize drilling, completion and production costs, while maximizing results, and (c) effective financial management. These core competencies are evidenced by the proven track record of its executive officers.
As of January 1, 2014, Oak Valley had an estimated 11,432 MBOE of proved reserves, consisting of 6,078 MBbls of oil, 24,213 MMcf of natural gas, and 1,318 MBbls of natural gas liquids. Approximately 32% of its proved reserves were classified as proved developed. Production for the year ended December 31, 2013, totaled 737 MBOE, or 2,019 BOE per day, of which 22% was oil. Production for the three months ended June 30, 2014, totaled 212 MBOE, or 2,325 BOE per day, of which 41% was oil. Production for the six months ended June 30, 2014, totaled 414 MBOE, or 2,286 BOE per day, of which 40% was oil.
Oak Valley pursues a value-driven growth strategy focused on pursuing projects that generate strong and predictable rates of return. This strategy is implemented through acquisitions, development drilling, and exploration activities that currently involve oil-weighted projects. Oak Valley emphasizes building production, reserves, and cash flows while continually seeking to expand its undeveloped acreage and drilling inventory. Oak Valley will continue to exploit its current assets and acreage positions through the cost-efficient drilling of economic reservoirs and production activities. Oak Valley’s current efforts are directed towards expanding its acreage position in the Eagle Ford trend located in the vicinity of its existing operations. Oak Valley may also consider conventional properties in close proximity to its existing operations, provided there is
economic production and cash flow, upside exploration or development potential and such properties can be effectively operated by Oak Valley’s field employees. Further, management will consider whether such properties may hold unconventional resource development potential. The acquisition of future assets will depend on the acreage or property and financing alternatives available to Oak Valley at the time it considers such opportunities. Oak Valley’s strategy includes expansion into the Bakken and other oil-prone areas of the Rockies, which it expects will be accelerated by the combination with Earthstone.
Oak Valley’s business strategy includes the following:
●
|
continuing the cost-effective development and exploration of acreage positions with a focus on its properties in the Eagle Ford trend;
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●
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expanding its acreage positions and drilling inventory in and around its focus areas through acquisitions and farm-in opportunities with an emphasis on operated positions and selective non-operated participations with other capable oil and gas operators;
|
●
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generating additional exploration and development projects in and around its focus areas;
|
●
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pursuing value-accretive corporate merger and acquisition opportunities;
|
●
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selectively divesting of non-core assets in order to streamline operations and utilize human and capital resources most effectively; and
|
●
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obtaining additional capital as needed, through the issuance of equity and debt securities.
|
Oak Valley’s fundamental operating and technical strategy is complemented by management’s commitment to increasing shareholder value by:
●
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maintaining a sound capital structure;
|
●
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promoting industry or institutional participants into projects to manage risk, enhancing rates of return, and lowering its net finding and development costs;
|
●
|
controlling capital, operating, and administrative costs; and
|
●
|
hedging a portion of production to provide a foundation of predictable cash flows to support development and exploration activities.
|
Oak Valley believes its strategy is appropriate because:
●
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it addresses multiple risks of oil and gas operations while providing equity holders with upside potential; and
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●
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it results in “staying power,” which management believes is essential to mitigate the adverse impacts of historically volatile commodity prices and financial markets.
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All of Oak Valley’s oil and gas reserves are located in the United States. Unaudited information concerning the estimated net quantities of all of Oak Valley’s proved reserves and the standardized measure of future net cash flows from the reserves is presented in Note 11 – “Disclosures About Oil and Gas Producing Activities (Unaudited),” in the Notes to the Historical Consolidated Financial Statements of Oak Valley in this proxy statement. Oak Valley’s reserve estimates have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), an independent petroleum engineering firm.
Set forth below is a summary of Oak Valley’s oil, natural gas and natural gas liquid reserves as of December 31, 2013 based on the reserve report prepared by CG&A. Oak Valley does not have any long-term supply or similar agreements with foreign governments or authorities. Oak Valley did not provide any reserve information to any federal agencies in 2013.
|
|
Oil
(MBbls)
|
|
|
Gas
(MMcf)
|
|
|
NGL
(MBbls)
|
|
|
Total
(MBOE)
|
|
|
Present Value Discounted
at 10% ($ in thousands) (1)
|
|
Proved developed
|
|
|
1,307 |
|
|
|
11,053 |
|
|
|
557 |
|
|
|
3,706 |
|
|
$ |
70,373 |
|
Proved undeveloped
|
|
|
4,771 |
|
|
|
13,160 |
|
|
|
761 |
|
|
|
7,726 |
|
|
$ |
54,984 |
|
Total proved
|
|
|
6,078 |
|
|
|
24,213 |
|
|
|
1,318 |
|
|
|
11,432 |
|
|
$ |
125,357 |
|
Oil, Gas and Natural Gas Liquids Reserve Quantities
|
|
Oil
(MBbl)
|
|
|
Gas
(MMcf)
|
|
|
NGL
(MBbls)
|
|
|
|
|
518 |
|
|
|
10,099 |
|
|
|
392 |
|
Purchase of minerals-in-place
|
|
|
2,051 |
|
|
|
709 |
|
|
|
213 |
|
Sales of minerals in place
|
|
|
(14 |
) |
|
|
– |
|
|
|
– |
|
Extensions and discoveries
|
|
|
3,586 |
|
|
|
4,198 |
|
|
|
526 |
|
Production
|
|
|
(163 |
) |
|
|
(2,635 |
) |
|
|
(134 |
) |
Revisions of quantity estimates
|
|
|
100 |
|
|
|
11,842 |
|
|
|
321 |
|
|
|
|
6,078 |
|
|
|
24,213 |
|
|
|
1,318 |
|
Ending proved developed reserve quantities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
296 |
|
|
|
8,245 |
|
|
|
268 |
|
|
|
|
1,307 |
|
|
|
11,053 |
|
|
|
557 |
|
(1)
|
Present Value Discounted at 10% (“PV-10”) is a non-GAAP measure that differs from the GAAP measure “standardized measure of discounted future net cash flows” in that PV-10 is calculated without regard to future income taxes. Oak Valley management believes that the presentation of PV-10 value is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to Oak Valley’s estimated proved reserves independent of its income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to its reserves. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, Oak Valley believes the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, Oak Valley management uses, and believes the industry generally uses, the PV-10 measure
in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties. PV-10 does not necessarily represent the fair market value of oil and gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For presentation of the standardized measure of discounted future net cash flows, please see Note 11 – “Disclosure About Oil and Gas Producing Activities (Unaudited)” in the Notes to the Historical Consolidated Financial Statements of Oak Valley included in this proxy statement. The table below titled “Non-GAAP Reconciliation” provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows.
|
|
Non-GAAP Reconciliation (in thousands)
|
|
The following table reconciles Oak Valley’s direct interest in oil and gas reserves as of December 31, 2013:
|
Present value of estimated future net revenues (PV-10)
|
|
$ |
125,357 |
|
Pro forma future income taxes, discounted at 10% (2)
|
|
|
(25,217 |
) |
Pro forma standardized measure of discounted future net cash flows
|
|
$ |
100,140 |
|
(2)
|
Oak Valley is a partnership and is not subject to income taxes; a pro forma adjustment has been made to Oak Valley’s standardized measure to reflect the effect of income taxes.
|
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond Oak Valley’s control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of the estimates, as well as economic factors such as change in commodity prices, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.
Proved Undeveloped Reserves
From January 1, 2013 to January 1, 2014, Oak Valley’s proved undeveloped reserves (“PUDs”) increased 1,080% from 655 MBOE to 7,726 MBOE, or an increase of 7,071 MBOE. This increase was primarily attributable to the acquisition of operated Eagle Ford properties in Gonzales and Fayette Counties, Texas, in July and August 2013 (“Operated Eagle Ford Asset Acquisition”). Additional drilling after acquiring the property increased PUDs and finally the increase in natural gas prices also increased the PUD reserves over the time frame. Oak Valley incurred approximately $32.5 million in development capital costs during 2013. Based on Oak Valley’s 2013 year-end independent engineering reserve report, Oak Valley plans to drill all of its individual PUD drilling locations within five years.
Preparation of Reserve Estimates
Oak Valley engaged an independent petroleum engineering consulting firm, CG&A, to prepare its annual reserve estimates and it has relied on CG&A’s expertise to ensure that Oak Valley’s reserve estimates are prepared in compliance with the SEC guidelines.
The technical person primarily responsible for the preparation of the reserve report is Mr. Robert D. Ravnaas, President of CG&A. He earned a Bachelor’s of Science degree with special honors in Chemical Engineering from the University of Colorado at Boulder in 1979 and a Master’s of Science degree in Petroleum Engineering from the University of Texas at Austin in 1981. Mr. Ravnaas is a Registered Professional Engineer in Texas and has more than 30 years of experience in the estimation and evaluation of oil and gas reserves. He is also a member of the Society of Petroleum Geologists, and Society of Professional Well Log Analysts.
Mr. Anderson, Oak Valley’s Executive Vice President responsible for reservoir engineering, is a qualified reserve estimator and auditor and is primarily responsible for overseeing its independent petroleum engineering firm during the preparation of its reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelors of Science degree in Petroleum Engineering from the University of Wyoming, 1986; Masters of Business Administration degree from the University of Denver, 1988; member of the Society of Petroleum Engineers since 1985; and more than 28 years of practical experience in estimating and evaluating reserve
information with more than five of those years being in charge of estimating and evaluating reserves.
Oak Valley maintains adequate and effective internal controls over its reserve estimation process as well as the underlying data upon which reserve estimates are based. The primary inputs to the reserve estimation process are technical information, financial data, ownership interest and production data. The relevant field and reservoir technical information, which is updated annually, is assessed for validity when Oak Valley’s independent petroleum engineering firm has technical meetings with Oak Valley’s engineers, geologists, operations and land personnel. Current revenue and expense information is obtained from Oak Valley’s accounting records, which are subject to external quarterly reviews, annual audits and its own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using
criteria set forth in “Internal Control – Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as commodity prices, lease operating expenses, production taxes and field-level commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete. Oak Valley’s current ownership in mineral interests and well production data are also subject to its internal controls over financial reporting, and they are incorporated in its reserve database as well and verified internally by Oak Valley personnel to ensure their accuracy and completeness. Once the reserve database has been updated with current information, and the relevant technical support material has been assembled, Oak Valley’s independent engineering firm meets with its technical personnel to review field performance and
future development plans in order to further verify the validity of estimates. Following these reviews, the reserve database is furnished to CG&A so that it can prepare its independent reserve estimates and final report. The reserve estimates prepared by CG&A are reviewed and compared to Oak Valley’s internal estimates by its Executive Vice President responsible for reservoir engineering and staff. Material reserve estimation differences are reviewed between CG&A and Oak Valley, and additional data is provided to address the differences. If the supporting documentation will not justify additional changes, the CG&A reserves are accepted. In the event that additional data supports a reserve estimation adjustment, CG&A will analyze the additional data, and may make changes it deems necessary. Additional data is usually comprised of updated production information on new wells. Once the review is completed and all material differences are reconciled, the
reserve report is finalized and Oak Valley’s reserve database is updated with the final estimates provided by CG&A.
Net Oil and Gas Production, Average Price and Average Production Cost
The net quantities of oil and gas produced and sold by Oak Valley for the years ended December 31, 2013, 2012, and 2011, and the three months ended March 31, 2014, the average sales price per unit sold and the average production cost per unit are presented below.
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
Oil Production (MBbls)
|
|
|
86 |
|
|
|
167 |
|
|
|
163 |
|
|
|
90 |
|
|
|
69 |
|
Gas Production (MMcf)
|
|
|
566 |
|
|
|
1,123 |
|
|
|
2,635 |
|
|
|
2,298 |
|
|
|
2,864 |
|
NGL Production (MBOE)
|
|
|
31 |
|
|
|
60 |
|
|
|
134 |
|
|
|
76 |
|
|
|
37 |
|
Total Production (MBOE)*
|
|
|
212 |
|
|
|
414 |
|
|
|
737 |
|
|
|
549 |
|
|
|
583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$ |
99.08 |
|
|
$ |
98.34 |
|
|
$ |
98.32 |
|
|
$ |
96.00 |
|
|
$ |
94.88 |
|
Gas per Mcf
|
|
|
4.58 |
|
|
|
4.76 |
|
|
|
3.69 |
|
|
|
2.64 |
|
|
|
4.21 |
|
NGL per BOE
|
|
|
30.50 |
|
|
|
31.83 |
|
|
|
28.88 |
|
|
|
31.00 |
|
|
|
44.20 |
|
BOE
|
|
|
57.00 |
|
|
|
57.12 |
|
|
|
40.22 |
|
|
|
31.13 |
|
|
|
34.66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
11.20 |
|
|
$ |
11.46 |
|
|
$ |
11.23 |
|
|
$ |
11.86 |
|
|
$ |
13.50 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes (which are included in lease operating expenses on Oak Valley’s consolidated statements of income) and severance taxes. Ad valorem taxes included in lease operating expenses were $126,000 and $253,000 for the three months and six months ended June 30, 2014, respectively, and $494,000, $271,000 and $300,000 in 2013, 2012 and 2011, respectively.
|
As of December 31, 2013, three fields accounted for 15% or more of Oak Valley’s proved reserves. Two of those fields, Southern Bay Eagleford and Eagleville, accounted for 30% and 22% of reserves, respectively. These two fields were acquired during 2013. The third field, Hawkville, was 22% of reserves in 2013, 63% in 2012 and 25% in 2011. Also in 2011, Oak Valley’s Red Oak Norris and Bokoshe South fields accounted for 21% and 16% of reserves, respectively. No other single field accounted for 15% or more of Oak Valley’s proved reserves in 2013, 2012 or 2011. The net quantities of oil, natural gas and natural gas liquids produced and sold by Oak Valley from these significant fields for each of the years ended December 31, 2013, 2012, and 2011,
the average sales price per unit sold and the average production cost per unit are presented below.
Southern Bay Eagleford Field
|
|
|
|
Oil Production (MBbls)
|
|
|
46 |
|
Gas Production (MMcf)
|
|
|
16 |
|
NGL Production (MBOE)
|
|
|
5 |
|
Total Production (MBOE)*
|
|
|
54 |
|
|
|
|
|
|
Average sales price (before the effects of hedging):
|
|
|
|
|
Oil per Bbl
|
|
$ |
100.43 |
|
Gas per Mcf
|
|
|
3.99 |
|
NGL per BOE
|
|
|
34.28 |
|
BOE
|
|
|
90.31 |
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
9.51 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes and severance taxes.
|
Eagleville Field
|
|
|
|
Oil Production (MBbls)
|
|
|
37 |
|
Gas Production (MMcf)
|
|
|
11 |
|
NGL Production (MBOE)
|
|
|
4 |
|
Total Production (MBOE)*
|
|
|
42 |
|
|
|
|
|
|
Average sales price (before the effects of hedging):
|
|
|
|
|
Oil per Bbl
|
|
$ |
99.84 |
|
Gas per Mcf
|
|
|
4.03 |
|
NGL per BOE
|
|
|
34.43 |
|
BOE
|
|
|
90.93 |
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
4.95 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes and severance taxes.
|
Hawkville Field
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Oil Production (MBbls)
|
|
|
56 |
|
|
|
69 |
|
|
|
16 |
|
Gas Production (MMcf)
|
|
|
1,362 |
|
|
|
761 |
|
|
|
498 |
|
NGL Production (MBOE)
|
|
|
125 |
|
|
|
75 |
|
|
|
34 |
|
Total Production (MBOE)*
|
|
|
407 |
|
|
|
272 |
|
|
|
133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (before the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$ |
95.67 |
|
|
$ |
96.53 |
|
|
$ |
87.91 |
|
Gas per Mcf
|
|
|
3.72 |
|
|
|
2.81 |
|
|
|
4.27 |
|
NGL per BOE
|
|
|
28.40 |
|
|
|
30.96 |
|
|
|
45.97 |
|
BOE
|
|
|
34.23 |
|
|
|
41.12 |
|
|
|
38.33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
8.70 |
|
|
$ |
5.38 |
|
|
$ |
4.28 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes and severance taxes.
|
Red Oak Norris Field
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Gas Production (MMcf)
|
|
|
131 |
|
|
|
121 |
|
|
|
181 |
|
Total Production (MBOE)*
|
|
|
22 |
|
|
|
20 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (before the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas per Mcf
|
|
$ |
3.22 |
|
|
$ |
2.23 |
|
|
$ |
3.52 |
|
BOE
|
|
|
19.34 |
|
|
|
13.39 |
|
|
|
21.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
8.75 |
|
|
$ |
14.06 |
|
|
$ |
10.25 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes and severance taxes.
|
Bokoshe South Field
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Gas Production (MMcf)
|
|
|
23 |
|
|
|
23 |
|
|
|
26 |
|
Total Production (MBOE)*
|
|
|
4 |
|
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price (before the effects of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas per Mcf
|
|
$ |
2.97 |
|
|
$ |
1.94 |
|
|
$ |
2.99 |
|
BOE
|
|
|
17.85 |
|
|
|
11.62 |
|
|
|
17.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost per BOE**
|
|
$ |
4.81 |
|
|
$ |
4.22 |
|
|
$ |
3.52 |
|
*
|
Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (1 BOE). Natural gas liquids have been converted to MBbls.
|
**
|
Excludes ad valorem taxes and severance taxes.
|
Oak Valley’s oil production is sold to large purchasers. Due to the quality and location of Oak Valley’s crude oil production, it may receive a discount or premium from index prices or “posted” prices in the area. Its gas production is sold primarily to pipeline and/or gas marketers under short-term contracts at prices which are tied to the “spot” market for gas sold in the area.
The purchasers of Oak Valley’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. In 2013, one purchaser accounted for 21% of Oak Valley’s oil, natural gas and NGL revenues. This purchaser is expected to be a significant purchaser in the future as well. No other purchaser accounted for 10% or more of Oak Valley’s oil, natural gas and NGL revenues during 2013, 2012 and 2011.
Oak Valley holds working interests in oil and gas properties for which third parties serve as operator. The operator sells the crude oil, natural gas and NGLs to the purchaser, and collects and distributes the revenue to Oak Valley. In 2013, two operators distributed 47% and 11% of Oak Valley’s total oil, natural gas and NGL revenues, respectively. In 2012, two operators distributed 65% and 18% of Oak Valley’s oil, natural gas and NGL revenues, respectively. In 2011, two operators distributed 25% and 33% of Oak Valley’s oil, natural gas and NGL revenues, respectively. No other operator accounted for 10% or more of Oak Valley’s oil, natural gas and NGL revenues during 2013, 2012 and 2011.
Gross and Net Productive Wells
As of December 31, 2013, Oak Valley’s total gross and net productive wells were as follows:
Productive Wells
Oil
|
|
Gas
|
|
Total
|
Gross Wells (1)
|
|
Net Wells
|
|
Gross Wells (1)
|
|
Net Wells
|
|
Gross Wells (1)
|
|
Net Wells
|
42
|
|
10.0
|
|
192
|
|
63.5
|
|
234
|
|
73.5
|
(1)
|
A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractions of working interests Oak Valley owns in gross wells. Productive wells are producing wells plus shut-in wells Oak Valley deems capable of production. Horizontal re-entries of existing wells do not increase a well total above one gross well. Oak Valley does not have any working interests in gross wells with completions into more than one productive zone.
|
Gross and Net Developed and Undeveloped Acres
As of December 31, 2013, Oak Valley had total gross and net developed and undeveloped leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated or permitted by state regulatory authorities.
Gross acres are those acres in which working interest is owned. The number of net acres represents the sum of fractional working interests Oak Valley owns in gross acres.
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
State
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Texas
|
|
|
63,300 |
|
|
|
16,800 |
|
|
|
59,900 |
|
|
|
31,000 |
|
|
|
123,200 |
|
|
|
47,800 |
|
All Others
|
|
|
19,700 |
|
|
|
17,000 |
|
|
|
– |
|
|
|
– |
|
|
|
19,700 |
|
|
|
17,000 |
|
Total
|
|
|
83,000 |
|
|
|
33,800 |
|
|
|
59,900 |
|
|
|
31,000 |
|
|
|
142,900 |
|
|
|
64,800 |
|
Exploratory Wells and Development Wells
Set forth below for the three years ended December 31, 2013 is information concerning the number of wells Oak Valley drilled during the years indicated.
|
|
Net Exploratory
Wells Drilled
|
|
|
Net Development
Wells Drilled
|
|
|
Total Net Productive
and Dry Wells
|
|
Year
|
|
Productive
|
|
|
Dry
|
|
|
Productive
|
|
|
Dry
|
|
|
Drilled
|
|
2013
|
|
|
0.2 |
|
|
|
0.0 |
|
|
|
2.8 |
|
|
|
0.0 |
|
|
|
3.0 |
|
2012
|
|
|
0.2 |
|
|
|
0.1 |
|
|
|
1.7 |
|
|
|
0.1 |
|
|
|
2.1 |
|
2011
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
1.4 |
|
|
|
0.0 |
|
|
|
1.4 |
|
As of September 15, 2014, Oak Valley had 18 gross (4.7 net) operated wells in the process of drilling or completing, and nine gross (0.9 net) non-operated wells in the process of drilling or completing.
Gas Purchase and Gas Processing Contract
Oak Valley has reserved gathering and processing capacity in one of the gas pipelines that services its operated Eagle Ford property. This contract is limited to two producing units within the operated Eagle Ford property out of a current total of 14 producing units. In that contract, which was ratified when the field was acquired, Oak Valley and the other working interest owners have a volume commitment, whereby they will pay the owner of the pipeline a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. Since the time of the acquisition, Oak Valley has not been able to meet the delivery commitments in the contract.
As of June 30, 2014, the estimated net cost of this commitment to Oak Valley is approximately $3.4 million, which will be reduced by any future gas sales revenues under the contract. The rate and terms under this purchasing and processing contract expire June 1, 2021.
As of June 30, 2014, Oak Valley had three drilling rigs under contract. Under the first drilling contract, Oak Valley contractually agreed to drill five wells at a drilling day rate of approximately $19,200 per day. As of June 30, 2014, Oak Valley drilled four wells and was in the process of drilling the fifth well. Early termination of the drilling rig contract prior to drilling all five wells to total depth would require a termination payment of $145,000. Under the second drilling contract,
Oak Valley contractually agreed to drill five wells at a drilling day rate of approximately $22,600 and five more wells at a drilling day rate of approximately $26,100 for a total of ten wells. As of June 30, 2014, Oak Valley completed drilling on four wells and drilling had not commenced on six wells. Early termination of the drilling rig contract prior to drilling all ten wells to total depth would require a termination payment of approximately $500,000. Under the third contract, Oak Valley entered into a six month drilling rig contract that commenced on May 24, 2014 and ends on November
24, 2014, at a drilling day rate of approximately $23,700 per day. As of June 30, 2014, termination of the contract subsequent to spudding of a well will require Oak Valley to pay approximately $2.2 million.
Oak Valley is the operator of properties containing approximately 61% of its proved oil and gas reserves and 77% of its proved PV-10 as of December 31, 2013. As operator, Oak Valley is able to directly influence exploration, development and production of operations. Oak Valley’s producing properties have reasonably predictable production profiles and cash flows, subject to commodity price fluctuations, and Oak Valley’s status as operator has allowed its technical staff to pursue the development of its undeveloped acreage, further develop its existing properties and generate new projects that Oak Valley believes have the potential to increase shareholder value.
As is common in the industry, Oak Valley participates in non-operated properties on a selective basis. Its non-operating participation decisions are dependent on the technical and economic nature of the projects and the operating expertise and financial standing of the operators.
The following is a description of Oak Valley’s major oil and gas properties.
Fayette County, Texas and Gonzales County, Texas
Operated Eagle Ford Asset Acquisition
As of September 15, 2014, Oak Valley had accumulated approximately 49,150 gross / 14,745 net leasehold acres in Gonzales and Fayette counties, Texas. The acreage is located in the volatile oil window of the Eagle Ford shale and is prospective for the Austin Chalk, Upper Eagle Ford, Buda, Wilcox and Edwards formations. Oak Valley serves as the operator with a 30% interest in the acreage.
As of September 15, 2014, Oak Valley operated 36 Eagle Ford wells and six Austin Chalk wells and had non-operated interests in two Eagle Ford wells and three Austin Chalk wells. Thirteen Eagle Ford wells and one Austin Chalk well are in the process of being drilled or were waiting on completion. Oak Valley is currently running two dedicated rigs and may increase to four rigs over the next twelve months. Oak Valley has identified a total of approximately 240 Eagle Ford drilling locations. The number of Eagle Ford locations could potentially increase subject to future down spacing parameters. In addition, the acreage position is prospective for the Austin Chalk, Upper Eagle Ford, Buda, Wilcox and Edwards formations, which may result in future economic locations. The majority of the acreage is covered by a 173
square mile 3-D seismic survey, which was initiated by Oak Valley technical personnel. Oak Valley is using the seismic survey to effectively develop the Eagle Ford and identify Austin Chalk locations and other opportunities.
Oak Valley is currently budgeting $7.5 million to $8.0 million to drill and complete Eagle Ford wells with lateral lengths of approximately 5,500 feet, and $4.0 million to $4.5 million to drill and complete Austin Chalk wells with lateral lengths of approximately 8,000 feet.
The acreage is subject to a joint operating agreement between Oak Valley and the majority working interest owner. Under the terms of that agreement, Oak Valley’s interest is subject to certain provisions governing disposition of the properties, including: (i) a co-sale (“tag-along”) right, which permits Oak Valley to sell its proportionate interest in the assets alongside any proposed sale transaction between the majority interest owner and a third-party buyer, (ii) a provision granting to Oak Valley a 45-day exclusive negotiation period which must elapse before the majority interest owner may enter into an agreement to sell its interest in the properties, and (iii) a drag-along provision, which obligates Oak Valley to sell its interest in the properties to a third-party buyer concurrent with a sale by the majority interest owner of its interest in the properties.
Oak Valley has a non-operated position in approximately 26,300 gross / 3,100 net acres in two areas within the Hawkville Field in La Salle County, Texas. The acreage is operated by BHP Billiton and is prone to gas and condensate derived from the Eagle Ford formation. The two areas are summarized below:
a)
|
White Kitchen – Oak Valley has a 15% working interest in approximately 7,600 gross acres, all of which is held by production. As of September 15, 2014, 30 wells were producing, and Oak Valley has identified approximately 40 additional drilling locations.
|
b)
|
Martin Ranch – Oak Valley has a 10% working interest in approximately 18,700 gross acres. As of June 14, 2014, 30 wells were producing, and Oak Valley has identified approximately 150 additional drilling locations. BHP Billiton is required to drill nine wells prior to May 2015, and six wells between May 2015 and May 2016, at which point a new drilling commitment, if any, may be contemplated.
|
Oak Valley holds approximately 21,500 gross / 18,900 net acres in Milam County, Texas, which is prospective for the Austin Chalk, Buda, Georgetown, Eagle Ford and Woodbine formations. The acreage is in reasonable proximity to areas with historical Buda production. Offset operators include Exxon, Slawson, and Anadarko.
Oak Valley holds approximately 2,600 gross / 1,300 net acres in Grayson County, Texas, which is prospective primarily for the Viola Lime formation. The primary independent offset operator has drilled and completed 16 horizontal wells. Oak Valley has participated in two successful wells, with working interests of 6% and 34%. Drilling and completion costs were approximately $7.5 million. The average production rates for the first 30 days in the two wells were 330 BOE/d and 462 BOE/d.
At the inception of Oak Valley, other producing properties located in South Texas, East Texas, North Louisiana, and eastern Oklahoma were contributed. While these properties do provide current production, cash flow, and future drilling locations, they are not consistent with Oak Valley’s long-term business strategy and may be divested in the future.
As of September 15, 2014, Oak Valley had 37 full-time employees, 29 of which are management, technical and administrative personnel, and eight of which are field employees. Contract personnel operate some of Oak Valley’s producing fields under the direct supervision of its employees. Oak Valley considers all relations with its employees to be good. None of Oak Valley’s employees is represented by a union and none is represented by collective bargaining agreements.
Oak Valley leases office space as disclosed in the following table.
|
|
|
|
|
|
|
The Woodlands, Texas
|
|
19,604 sq. ft.
|
|
|
|
Office
|
Houston, Texas
|
|
15,626 sq. ft.
|
|
|
|
Office
|
Denver, Colorado
|
|
695 sq. ft.
|
|
|
|
Office
|
During 2013, aggregate rental payments for Oak Valley’s office facilities totaled approximately $120,000. In March 2014, Oak Valley exercised an early termination option effective November 30, 2014 on its Houston, Texas office lease, at which point employees will be relocated to an office in The Woodlands, Texas. The Woodlands lease will commence upon substantial completion of construction associated with the space, presently estimated to occur in the fourth quarter of 2014.
From time to time, Oak Valley is a party to litigation or other legal proceedings that it considers to be a part of the ordinary course of its business. Oak Valley is not currently involved in any legal proceedings, nor is it a party to any pending or threatened claims, that could reasonably be expected to have a material adverse effect on its financial condition or results of operations.
Executive Officers of Oak Valley
The following table sets forth certain information as of September 15, 2014, regarding Oak Valley’s executive officers:
Name
|
|
Age
|
|
Position with Oak Valley
|
|
|
64 |
|
Chief Executive Officer and President
|
Robert J. Anderson
|
|
52 |
|
Executive Vice President, Corporate Development and Engineering
|
Steven C. Collins
|
|
49 |
|
Executive Vice President, Completions and Operations
|
Christopher E. Cottrell
|
|
54 |
|
Executive Vice President, Land and Marketing
|
Timothy D. Merrifield
|
|
58 |
|
Executive Vice President, Geology and Geophysics
|
Francis M. Mury
|
|
62 |
|
Executive Vice President, Drilling and Development
|
G. Bret Wonson
|
|
36 |
|
Vice President, Principal Accounting Officer
|
Neil K. Cohen
|
|
32 |
|
Vice President, Finance
|
Frank A. Lodzinski has served as Oak Valley’s President and Chief Executive Officer since its formation in December 2012. Mr. Lodzinski was Chairman, President and Chief Executive Officer of GeoResources, Inc. from April 2007 until its merger with Halcón Resources Corporation in August 2012. He has over 43 years of oil and gas industry experience. In 1984, he formed Energy Resource Associates, Inc., which acquired management and controlling interests in oil and gas limited partnerships, joint ventures and producing properties. Certain partnerships were exchanged for common shares of Hampton Resources Corporation in 1992, which Mr. Lodzinski joined as a director and President. Hampton was sold in 1995 to Bellwether Exploration Company. In 1996, he formed Cliffwood Oil & Gas Corp. and in 1997, Cliffwood shareholders acquired a controlling
interest in Texoil, Inc., where Mr. Lodzinski served as CEO and President. In 2001, Mr. Lodzinski was appointed CEO and President of AROC, Inc., to direct the restructuring and ultimate liquidation of that company. In 2003, AROC completed a monetization of oil and gas assets with an institutional investor and began a plan of liquidation in 2004. In 2004, Mr. Lodzinski formed Southern Bay Energy, LLC, the general partner of Southern Bay Oil & Gas, L.P., which acquired the residual assets of AROC, Inc., and he served as President of Southern Bay Energy, LLC since its formation. He holds a BSBA degree in Accounting and Finance from Wayne State University in Detroit, Michigan. Mr. Lodzinski, as Earthstone’s President and Chief Executive Officer after the business combination, will be responsible for the business strategy. His industry experience, prior roles in managing
publicly traded oil and gas companies, and vision will be an important component of Earthstone’s operations. Mr. Lodzinski’s leadership and intimate knowledge of the oil and gas industry, Earthstone’s structure, and its operations, including those of Oak Valley, provide the Board of Directors with company-specific experience and expertise.
Robert J. Anderson is a petroleum engineer with over 28 years of diversified domestic and international experience. He has been working with Mr. Lodzinksi’s management team for approximately 10 years. Mr. Anderson has been employed by Oak Valley since March 2013 as Executive Vice President, Corporate Development and Engineering. Prior to employment by Oak Valley, he served from August 2012 to February 2013 as Executive Vice President and Chief Operating Officer at Halcón Resources. Mr. Anderson was employed by GeoResources from April 2012 until its merger with Halcón Resources in August 2012, ultimately serving as a director and Executive Vice President, Chief Operating Officer – Northern Region. He was involved in the formation of Southern Bay Energy in September 2004 as Vice President, Acquisitions until its merger with GeoResources
in April 2007. From March 2004 to August 2004, Mr. Anderson was employed by AROC, a predecessor company to Southern Bay Energy, as Vice President, Acquisitions and Divestitures. From September 2000 to February 2004, he was employed by Anadarko Petroleum Corporation as a petroleum engineer. In addition, he has worked with major oil companies, including ARCO International/Vastar Resources, and independent oil companies, including Hunt Oil, Hugoton Energy, and Pacific Enterprises Oil Company. His professional experience includes acquisition evaluation, reservoir and production engineering, field development, project economics, budgeting and planning, and capital markets. His domestic acquisition and divestiture experience includes Texas and Louisiana (offshore and onshore), Mid-Continent, and the Rocky Mountain states, and international experience includes Canada, South America, and Russia. Mr. Anderson has a B.S. degree in Petroleum Engineering from the University of Wyoming
and an MBA from the University of Denver.
Steven C. Collins is a petroleum engineer with over 26 years of operations and related experience. He has been working with Mr. Lodzinski’s management team for approximately 18 years. Mr. Collins has been employed by Oak Valley since December 2012 as Executive Vice President, Completions and Operations. Prior to employment by Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón Resources. Mr. Collins was employed by GeoResources from April 2007 until its merger with Halcón Resources in August 2012 and directed all field operations, including production, workover, recompletion, and drilling operations. Prior to employment by GeoResources, he served as operations manager for Southern Bay, AROC, and Texoil, and as a petroleum and operations engineer at Hunt Oil Company and Pacific Enterprises Oil Company. His experience includes Texas, Louisiana (onshore and offshore), North
Dakota, Montana, and the Mid-Continent. Mr. Collins graduated with a B.S. degree in Petroleum Engineering from the University of Texas.
Christopher E. Cottrell has been employed in various aspects of land management and commodity marketing activities since 1983. He has been working with Mr. Lodzinski’s management team for approximately 16 years. Mr. Cottrell has been employed by Oak Valley since December 2012 as Executive Vice President, Land and Marketing. Prior to employment by Oak Valley, he was employed by GeoResources from April 2007 until its merger with Halcón Resources in August 2012, ultimately serving as Vice President of Land and Marketing, responsible for land and operating contract matters including oil and gas marketing, land and lease records, title and division orders. In addition, he was actively involved in due diligence associated with business development matters. He has held previous roles at AROC, Texoil, Williams
Exploration, Ashland Exploration, American Exploration, Belco Energy, and Citation Oil & Gas. Mr. Cottrell graduated with a B.B.A. degree in Petroleum Land Management from the University of Texas.
Timothy D. Merrifield has over 35 years of oil and gas industry experience. He has been working with Mr. Lodzinski’s management team for approximately 13 years. Mr. Merrifield has been employed by Oak Valley since December 2012 as Executive Vice President, Geology and Geophysics. Prior to employment by Oak Valley, he served from August 2012 to November 2012 as a consultant to Halcón Resources upon its merger with GeoResources in August 2012. From April 2007 to August 2012, Mr. Merrifield led all geology and geophysics efforts at GeoResources. He has held previous roles at AROC, Force Energy, Great Western Resources and other independents. His domestic experience includes Texas, Louisiana (onshore and offshore), North Dakota, Montana, New Mexico, Rocky Mountain states, and the Mid-Continent. In addition, he has international experience in Peru and the East Irish Sea. Mr. Merrifield attended Texas Tech
University.
Francis M. Mury has over 40 years of oil and gas industry experience. He has been working with this management team for approximately 24 years. Mr. Mury has been employed by Oak Valley since December 2012 as Executive Vice President, Drilling and Development. Prior to employment by Oak Valley, he was employed by GeoResources from April 2007 until its merger with Halcón Resources in August 2012, ultimately serving as an Executive Vice President, Chief Operating Officer–Southern Region. He has held prior roles at AROC, Texoil, Hampton Resources, Wainoco Oil & Gas Company, Diasu Exploration Company, and Texaco, Inc. His experience extends to all facets of petroleum engineering, including reservoir engineering, drilling and production operations, petroleum economics, geology, geophysics, land, and joint operations. Geographical areas of experience include Texas and Louisiana (offshore and onshore),
North Dakota, Montana, Mid-Continent, Florida, New Mexico, Oklahoma, Wyoming, Pennsylvania, and Michigan. Mr. Mury graduated from Nicholls State University.
G. Bret Wonson has over 13 years of professional experience. He has been working with this management team for approximately five years. Mr. Wonson has been employed by Oak Valley since February 2013 as Vice President, Principal Accounting Officer. Prior to Oak Valley, he served from August 2012 to February 2013 as Assistant Controller at Halcón Resources upon its merger with GeoResources in August 2012. From February 2012 to August 2012 and from April 2008 to November 2010, Mr. Wonson was Corporate Controller and Controller of GeoResources, respectively. From December 2010 to January 2012, he was an Assistant Controller at Valerus Compression. He has held previous roles at Arthur Andersen, Grant Thornton, and BP. Mr. Wonson holds a bachelor’s degree in Accounting from Mississippi State University and a Master’s degree in Accounting from the University of Alabama. Mr. Wonson is a Certified Public Accountant
in the State of Texas.
Neil K. Cohen has over 11 years of professional experience. He has been working with this management team for approximately two years. Mr. Cohen has been employed by Oak Valley since December 2012 as Vice President, Finance. He is primarily responsible for all finance, valuation, capital markets, and investor relations activities. Prior to joining Oak Valley, he served from September 2012 to December 2012 as a consultant to Texoil Energy, Inc. From February 2006 to October 2011, Mr. Cohen was employed by UBS Investment Bank as a member of the Global Energy Group, with exposure to all energy subsectors and a particular emphasis on exploration and production companies, and as a member of UBS’ Debt Capital Markets Group, with a particular emphasis on investment grade energy and utility issuers. He has held previous roles
at Merrill Lynch (Debt Capital Markets and Debt Derivatives Finance) and Hess Corporation (Finance). Mr. Cohen graduated with a B.S. degree in Finance from the University of Maryland.
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF OAK VALLEY
The following discussion should be read in conjunction with the financial statements of Oak Valley and the notes thereto included elsewhere in this proxy statement. The following discussion includes certain forward-looking statements. For a discussion of important factors which could cause actual results to differ materially from the results referred to in the forward-looking statements, see “Risk Factors – Risk Factors Associated with the Combined Company” and “Cautionary Statement Regarding Forward-Looking Statements.”
Oak Valley is an independent, domestic oil and gas company focused on the acquisition, development, exploration and production of onshore, unconventional oil and natural gas reserves. Oak Valley owns three subsidiary limited liability companies which hold all of Oak Valley’s oil and gas properties. Oak Valley’s current operations are concentrated in the Eagle Ford trend of South Texas where it holds both operating and non-operating interests.
Oak Valley was initially capitalized on December 21, 2012, with producing properties and acreage (“Contributed Properties”), working capital, and $100 million of cash commitments from affiliates of EnCap Investments L.P. and an aggregate of approximately $52 million of cash commitments from management and employees of Oak Valley, an affiliate of Wells Fargo Energy Capital, and an affiliate of Vlasic Group. On April 25, 2013, Oak Valley closed a private placement of approximately $63 million of cash commitments from accredited investors.
Although Oak Valley was a newly created entity, pursuant to GAAP guidelines it is required to retain the historical cost basis and report the historical results of operations and financial position of the Contributed Properties. Such historical cost basis was in excess of the valuation agreed upon by the members at the time of capitalization (“Equity Valuation”), resulting in higher depletion, depreciation and amortization (“DD&A”) provisions and the recognition of impairments in financial carrying values in 2013 and 2012 than would otherwise be reported based on the Equity Valuation. As of December 31, 2013, the net book value of Contributed Properties has been reduced to less than the Equity Valuation through DD&A expense and impairments determined in accordance with GAAP. See Note 2 – “Summary of Significant Accounting Policies” and Note 5 –
“Fair Value Measurements” in the Notes to the Historical Consolidated Financial Statements of Oak Valley included in this proxy statement.
As of January 1, 2014, Oak Valley had an estimated 11,432 MBOE of proved reserves, consisting of 6,078 MBbls of oil, 24,213 MMcf of natural gas, and 1,318 MBbls of natural gas liquids. Approximately 32% of Oak Valley’s proved reserves were classified as proved developed. Production for the twelve months ended December 31, 2013, totaled 737 MBOE, or 2,019 BOE per day, of which 22% was oil. Production for the three months ended June 30, 2014, totaled 212 MBOE, or 2,325 BOE per day, of which 41% was oil. Production for the six months ended June 30, 2014, totaled 414 MBOE, or 2,286 BOE per day, of which 40% was oil.
Critical Accounting Policies
Critical accounting policies are defined as those that are reflecting of significant judgments and uncertainties and that could potentially result in materially different results under different assumptions and conditions. For a detailed description of Oak Valley’s accounting policies, see Note 2 – “Summary of Significant Accounting Policies” in the Notes to the Historical Consolidated Financial Statements of Oak Valley included in this proxy statement.
Sales and Other Operating Revenues
The quantities of oil and condensate, natural gas and natural gas liquids sold by Oak Valley for the three months ended June 30, 2014 and 2013, and the average sales price per unit sold are presented below.
|
|
Three Months Ended
|
|
|
|
|
|
|
2013
|
|
Sales volumes:
|
|
|
|
|
|
|
Oil and condensate (MBbl)
|
|
|
86 |
|
|
|
22 |
|
Natural gas (MMcf)
|
|
|
566 |
|
|
|
760 |
|
Natural gas liquids (MBbl)
|
|
|
31 |
|
|
|
41 |
|
Barrel of oil equivalent (MBOE)
|
|
|
212 |
|
|
|
189 |
|
|
|
|
|
|
|
|
|
|
Average prices realized:
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
$ |
99.08 |
|
|
$ |
95.66 |
|
Natural gas (per Mcf)
|
|
$ |
4.58 |
|
|
$ |
4.01 |
|
Natural gas liquids (per Bbl)
|
|
$ |
30.50 |
|
|
$ |
26.87 |
|
Oak Valley’s revenues for the three months ended June 30, 2014 and 2013 are summarized in the table below:
|
|
Three Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
Oil, natural gas and natural gas liquids revenues:
|
|
|
|
|
|
|
Oil and condensate
|
|
$ |
8,508 |
|
|
$ |
2,042 |
|
Natural gas
|
|
|
2,593 |
|
|
|
3,045 |
|
Natural gas liquids
|
|
|
957 |
|
|
|
1,122 |
|
|
|
|
|
|
|
|
|
|
Other operating revenues:
|
|
|
|
|
|
|
|
|
Realized loss on commodity derivatives
|
|
|
(549 |
) |
|
|
(11 |
) |
Unrealized gain/(loss) on commodity derivatives
|
|
|
(726 |
) |
|
|
306 |
|
Gathering income
|
|
|
86 |
|
|
|
133 |
|
Loss on sale of oil & gas properties
|
|
|
– |
|
|
|
(54 |
) |
Sale of Crude Oil and Condensate
For the three months ended June 30, 2014, oil and condensate revenues increased by $6,466,000 relative to the comparable period in 2013. Of the increase, $6,173,000 was due to volume and $293,000 was attributable to an increase in realized price. Oil and condensate sales volumes increased by 64 MBbls, consisting of 68 MBbls produced from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013, which was offset by natural declines from other properties. Average realized price per Bbl increased from $95.66 for the three months ended June 30, 2013 to $99.08 for the three months ended June 30, 2014.
For the three months ended June 30, 2014, natural gas revenues decreased $452,000 relative to the comparable period in 2013. Of the decrease, $778,000 was due to volume, which was offset by $326,000 attributable to an increase in realized price. Natural gas sales volumes decreased by 194 MMcf primarily due to a decline in sales volumes of 176 MMcf from non-operated Eagle Ford properties in La Salle County, Texas and a 45 MMcf decline from other properties, which was offset by production of 27 MMcf from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. Average realized price per Mcf increased from $4.01 for the three months ended June 30, 2013 to $4.58 for the three months ended June 30, 2014.
Sale of Natural Gas Liquids
For the three months ended June 30, 2014, natural gas liquids revenues decreased $165,000 relative to the comparable period in 2013. Of the decrease, $279,000 was due to volume offset by $114,000 attributable to an increase in realized price. Natural gas liquids sales volumes decreased by 10 MBbls primarily due to a decline in production of 17 MBbls from non-operated Eagle Ford properties in La Salle County, Texas, which was offset by production of 7 MBbls from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. Average realized price per Bbl increased from $26.87 for the three months ended June 30, 2013 to $30.50 for the three months ended June 30, 2014.
During the three months ended June 30, 2014, Oak Valley recorded a loss on derivative contracts of $1,275,000, consisting of a realized loss on derivative settlements of $549,000 and an unrealized loss of $726,000. During the comparable period in 2013, a net gain of $295,000 was recorded, consisting of a realized loss on derivative settlements of $11,000, which was offset by an unrealized mark-to-market gain of $306,000. A larger loss on derivative settlements was realized in the current period due to a larger quantity of volumes hedged and the level of settlement prices.
|
|
Three Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
Lease operating expenses
|
|
$ |
2,376 |
|
|
$ |
2,200 |
|
Severance taxes
|
|
|
509 |
|
|
|
236 |
|
Re-engineering and workover expenses
|
|
|
122 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
LOE per BOE*
|
|
$ |
10.27 |
|
|
$ |
11.29 |
|
Severance taxes as a percent of oil, natural gas, and natural gas liquids revenue
|
|
|
4.22 |
% |
|
|
3.80 |
% |
* Excludes ad valorem taxes and accretion expense related to the asset retirement obligation.
Lease operating expenses (“LOE”) include all costs incurred to operate wells and related facilities for operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE also includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements. Ad valorem taxes included in LOE for the three months ended June 30, 2014 and 2013 were $127,000 and $0, respectively.
LOE increased by $176,000 for the three months ended June 30, 2014 relative to the comparable period in 2013. The increase in LOE was primarily due to the Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 9%, or $1.02 per BOE, to $10.27 per BOE for the three months ended June 30, 2014. The decrease on a unit-of-production basis results from a growing portion of total company production being attributable to new wells with strong production rates and cost-effective operations. Ad valorem taxes in 2014 increased relative to the comparable period in 2013 by $127,000 due to higher assessed property values.
Severance taxes increased by $273,000 to $509,000 for the three months ended June 30, 2014 relative to the comparable period in 2013. The increase in severance taxes was primarily due to production from Operated Eagle Ford Asset Acquisition properties that were acquired during the second half of 2013. As a percentage of revenues from oil and condensate, natural gas and natural gas liquids, severance taxes incurred increased from 3.8% to 4.2%. This increase is attributable to the Operated Eagle Ford Asset Acquisition, which added a significant amount of production from wells that produce primarily oil and are not subject to tax exemptions, whereas in the 2013 period, a significant amount of the new production was from high-cost gas wells that qualify for full or partial severance tax exemptions.
Re-engineering and Workovers
Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.
Re-engineering and workover expenses increased from $116,000 to $122,000 during the three months ended June 30, 2014 relative to the comparable period in 2013. During the 2014 period, Oak Valley began completing several projects associated with integrating the Operated Eagle Ford Asset Acquisition properties into its operations and reducing the rate at which these wells decline. During 2013, Oak Valley worked on projects that were aimed at reducing the rate at which its unconventional wells decline and the operating costs of its conventional wells.
General and Administrative Expenses
General and administrative (“G&A”) expenses primarily consist of overhead expenses, employee remuneration, and professional and consulting fees.
G&A expenses increased by $294,000 from $1,508,000 to $1,802,000 during the three months ended June 30, 2014 relative to the comparable period in 2013. The increase was primarily due to professional fees included in the 2014 period that were related to the pending exchange with Earthstone.
Depreciation, Depletion and Amortization and Impairment Expense
|
|
Three Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
DD&A
|
|
$ |
4,383 |
|
|
$ |
6,201 |
|
Impairment
|
|
|
– |
|
|
|
44 |
|
DD&A per BOE
|
|
$ |
20.72 |
|
|
$ |
32.68 |
|
Depreciation, Depletion and Amortization
DD&A decreased by $1,818,000, or 29%, during the three months ended June 30, 2014 relative to the comparable period in 2013. On a unit-of-production basis, DD&A per BOE decreased from $32.68 during 2013 to $20.72 during 2014. The decrease was due to significant impairments incurred on legacy properties during 2013. Oak Valley was capitalized on December 21, 2012, and acquired certain subsidiaries in exchange for equity as part of a larger transaction. In accordance with GAAP, this transaction was treated as a common control transaction and as such Oak Valley was required to retain the historical cost basis for the legacy assets. As of December 31, 2013, the net book value of these
properties was reduced through impairment charges to its fair value.
Oak Valley’s annual impairment assessment occurs in the fourth quarter. During the three months ended June 30, 2014, there were no triggering events, and therefore, no impairment expense was recognized. An impairment of $44,000 related to certain wells located in Oklahoma was recorded during the three months ended June 30, 2013.
Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Debt outstanding as of June 30, 2014 and 2013 was $10,825,000.
Interest expense increased from $102,000 during the three months ended June 30, 2013 to $152,000 during the three months ended June 30, 2014. The $50,000 increase in interest expense was due to higher commitment fees as a result of a larger unused borrowing base as well as higher amortization of deferred financing costs.
Oak Valley is a disregarded entity for federal and state income tax purposes and therefore does not pay or accrue for such taxes.
Sales and Other Operating Revenues
The quantities of oil and condensate, natural gas and natural gas liquids sold by Oak Valley for the six months ended June 30, 2014 and 2013, and the average sales price per unit sold are presented below.
|
|
Six Months Ended
|
|
|
|
|
|
|
2013
|
|
Sales volumes:
|
|
|
|
|
|
|
Oil and condensate (MBbl)
|
|
|
167 |
|
|
|
32 |
|
Natural gas (MMcf)
|
|
|
1,123 |
|
|
|
1,234 |
|
Natural gas liquids (MBbl)
|
|
|
60 |
|
|
|
57 |
|
Barrel of oil equivalent (MBOE)
|
|
|
414 |
|
|
|
294 |
|
|
|
|
|
|
|
|
|
|
Average prices realized:
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
$ |
98.34 |
|
|
$ |
98.20 |
|
Natural gas (per Mcf)
|
|
$ |
4.76 |
|
|
$ |
3.75 |
|
Natural gas liquids (per Bbl)
|
|
$ |
31.83 |
|
|
$ |
27.45 |
|
Oak Valley’s revenues for the six months ended June 30, 2014 and 2013, are summarized in the table below:
|
|
Six Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
Oil, natural gas and natural gas liquids revenues:
|
|
|
|
|
|
|
Oil and condensate
|
|
$ |
16,376 |
|
|
$ |
3,126 |
|
Natural gas
|
|
|
5,346 |
|
|
|
4,631 |
|
Natural gas liquids
|
|
|
1,914 |
|
|
|
1,562 |
|
|
|
|
|
|
|
|
|
|
Other operating revenues:
|
|
|
|
|
|
|
|
|
Realized loss on commodity derivatives
|
|
|
(1,088 |
) |
|
|
(11 |
) |
Unrealized gain/(loss) on commodity derivatives
|
|
|
(1,215 |
) |
|
|
238 |
|
Gathering income
|
|
|
195 |
|
|
|
250 |
|
Loss on sale of oil & gas properties
|
|
|
– |
|
|
|
(54 |
) |
Sale of Crude Oil and Condensate
For the six months ended June 30, 2014, oil and condensate revenues increased by $13,250,000 relative to the comparable period in 2013. Of the increase, $13,227,000 was due to volume and $23,000 was attributable to an increase in realized price. Oil and condensate sales volumes increased by 135 MBbls, consisting of 128 MBbls produced from Operated Eagle Ford Asset Acquisition properties and 12 MBbls from recently drilled non-operated wells in Grayson County, Texas, which was offset by natural declines from non-operated Eagle Ford properties in La Salle County, Texas and other properties. Average realized price per Bbl increased from $98.20 for the six months ended June 30, 2013 to $98.34 for the six months ended June 30, 2014.
For the six months ended June 30, 2014, natural gas revenues increased $715,000 relative to the comparable period in 2013. Of the increase, $1,133,000 was due to realized price, which was offset by $418,000 attributable to volume. Natural gas sales volumes decreased by 111 MMcf primarily due to a decline in production of 69 MMcf from non-operated Eagle Ford properties in La Salle County, Texas and a decline in production of 63 MMcf from Oak Valley’s non-operated East Texas Properties, which was offset by production of 49 MMcf from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. The remaining decrease of 28 MMcf was due to natural declines from other properties. Average realized price per Mcf increased from $3.75 for the six months ended June 30, 2013 to $4.76 for the six months
ended June 30, 2014.
Sale of Natural Gas Liquids
For the six months ended June 30, 2014, natural gas liquids revenues increased $352,000 relative to the comparable period in 2013. Of the increase, $88,000 was due to volume and $264,000 was attributable to an increase in realized price. Natural gas liquids sales volumes increased by 3 MBbls. The volume increase was primarily due to sales of 13 MBbls from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013, which was offset by a decline of 10 MBbls from non-operated Eagle Ford properties in La Salle County, Texas. Average realized price per Bbl increased from $27.45 for the six months ended June 30, 2013 to $31.83 for the six months ended June 30, 2014.
During the six months ended June 30, 2014, Oak Valley recorded a loss on derivative contracts of $2,303,000, consisting of a realized loss on derivative settlements of $1,088,000 and an unrealized loss of $1,215,000. During the comparable period in 2013, a net gain of $227,000 was recorded, consisting of a realized loss on derivative settlements of $11,000, which was offset by an unrealized mark-to-market gain of $238,000. A larger loss on derivative settlements was realized in the current period due to a larger quantity of volumes hedged and the level of settlement prices.
Production Costs
|
|
Six Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
Lease operating expenses
|
|
$ |
4,674 |
|
|
$ |
3,447 |
|
Severance taxes
|
|
|
998 |
|
|
|
345 |
|
Re-engineering and workover expenses
|
|
|
320 |
|
|
|
144 |
|
|
|
|
|
|
|
|
|
|
LOE per BOE*
|
|
$ |
10.32 |
|
|
$ |
11.34 |
|
Severance taxes as a percent of oil, natural gas, and natural gas liquids revenue
|
|
|
4.22 |
% |
|
|
3.70 |
% |
* Excludes ad valorem taxes and accretion expense related to the asset retirement obligation.
LOE includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements. Ad valorem taxes included in LOE for the six months ended June 30, 2014 and 2013 were $253,000 and $5,000, respectively.
LOE increased by $1,227,000 for the six months ended June 30, 2014 relative to the comparable period in 2013. The increase in LOE was primarily due to Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, decreased by 9%, or $1.02 per BOE, to $10.32 per BOE for the six months ended June 30, 2014. The decrease on a unit-of-production basis results from a growing portion of total company production being attributable to new wells with strong production rates and cost-effective operations. Ad valorem taxes in 2014 increased relative to the comparable period in 2013 by $248,000 due to higher assessed property values.
Severance taxes increased by $653,000 to $998,000 for the six months ended June 30, 2014 relative to the comparable period in 2013. The increase in severance taxes was primarily due to production from Operated Eagle Ford Asset Acquisition properties that were acquired during 2013. As a percentage of revenues from oil and condensate, natural gas, and natural gas liquids, severance taxes increased from 3.7% to 4.2%. This increase is attributable to the Operated Eagle Ford Asset Acquisition, which added a significant amount of production from wells that produce primarily oil and are not subject to tax exemptions, whereas in the 2013 period, a significant amount of the new production was from high-cost gas wells that qualify for full or partial severance tax exemptions.
Re-engineering and Workovers
Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.
Re-engineering and workover expenses increased from $144,000 to $320,000 during the six months ended June 30, 2014 relative to the comparable period in 2013. During the 2014 period, Oak Valley began completing several projects associated with integrating the Operated Eagle Ford Asset Acquisition properties into its operations and reducing the rate at which those wells decline. During 2013, Oak Valley worked on projects that were aimed at reducing the rate at which its conventional and unconventional wells decline.
General and Administrative Expenses
G&A expenses primarily consist of overhead expenses, employee remuneration, and professional and consulting fees.
G&A expenses increased by $114,000 from $3,100,000 to $3,214,000 during the six months ended June 30, 2014 relative to the comparable 2013 period. The increase was primarily attributable to an $886,000 increase in salary costs due to increased headcount. The increased salary expenses were offset by a $388,000 increase in operating 2013 overhead income from the operation of the wells and the drilling activity at Oak Valley’s operated Eagle Ford asset. Operating overhead income, which is a reimbursement for indirect overhead expenses incurred by the operator, is provided for in the joint operating agreements for properties that Oak Valley’s subsidiaries act as the operator. This income is included in G&A expenses in order to match the reimbursement with the indirect
expenses. Additionally, the 2013 period included $281,000 of professional fees primarily related to due diligence costs and audits related to the December 2012 formation and capitalization of Oak Valley. The 2013 period also included $142,000 of employee severance costs related to the change in management from the December 2012 formation and capitalization. The remaining difference was due to professional fees and other costs incurred during the 2014 period that were related to the pending exchange with Earthstone and other corporate activities.
Depreciation, Depletion and Amortization and Impairment Expense
|
|
Six Months Ended
June 30,
|
|
|
|
(in thousands)
|
|
|
|
2014
|
|
|
2013
|
|
DD&A
|
|
$ |
7,763 |
|
|
$ |
8,998 |
|
Impairment
|
|
|
– |
|
|
|
44 |
|
DD&A per BOE
|
|
$ |
18.76 |
|
|
$ |
30.55 |
|
Depreciation, Depletion and Amortization
DD&A decreased by $1,235,000, or 14%, during the six months ended June 30, 2014 relative to the comparable period in 2013. On a unit-of-production basis, DD&A per BOE decreased from $30.55 during 2013 to $18.76 during 2014. The decrease was due to significant impairments incurred on legacy properties during 2013. Oak Valley was capitalized on December 21, 2012, and acquired certain subsidiaries in exchange for equity as part of a larger transaction. In accordance with GAAP, this transaction was treated as a common control transaction and as such Oak Valley was required to retain the historical cost basis for the legacy assets. As of December 31, 2013, the net book
value of these properties was reduced to its estimated fair value through impairment charges.
Oak Valley’s annual impairment assessment occurs in the fourth quarter. During the six months ended June 30, 2014, there were no triggering events, and therefore, no impairment expense was recognized. An impairment of $44,000 related to certain wells located in Oklahoma was recorded during the six months ended June 30, 2013.
Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Debt outstanding as of June 30, 2014 and 2013 was $10,825,000.
Interest expense increased from $195,000 during the six months ended June 30, 2013 to $297,000 during the six months ended June 30, 2014. The $102,000 increase in interest expense was due to higher commitment fees as a result of a larger unused borrowing base as well as higher amortization of deferred financing costs.
Oak Valley is a disregarded entity for federal and state income tax purposes and therefore does not pay or accrue for such taxes.
Sales and Other Operating Revenues
The quantities of oil and condensate, natural gas, and natural gas liquids sold by Oak Valley for the twelve months ended December 31, 2013, 2012, and 2011, and the average sales price per unit sold are presented below.
|
|
Twelve Months Ended
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbl)
|
|
|
163 |
|
|
|
90 |
|
|
|
69 |
|
Natural gas (MMcf)
|
|
|
2,635 |
|
|
|
2,298 |
|
|
|
2,864 |
|
Natural gas liquids (MBbl)
|
|
|
134 |
|
|
|
76 |
|
|
|
37 |
|
Barrel of oil equivalent (MBOE)
|
|
|
737 |
|
|
|
549 |
|
|
|
583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average prices realized:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (per Bbl)
|
|
$ |
98.32 |
|
|
$ |
96.00 |
|
|
$ |
94.88 |
|
Natural gas (per Mcf)
|
|
$ |
3.69 |
|
|
$ |
2.64 |
|
|
$ |
4.21 |
|
Natural gas liquids (per Bbl)
|
|
$ |
28.88 |
|
|
$ |
31.00 |
|
|
$ |
44.20 |
|
|
|
Twelve Months Ended
December 31,
|
|
|
|
(in thousands)
|
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
Oil, natural gas and natural gas liquids revenues:
|
|
|
|
|
|
|
|
|
|
Oil and condensate
|
|
$ |
16,038 |
|
|
$ |
8,679 |
|
|
$ |
6,518 |
|
Natural gas
|
|
|
9,714 |
|
|
|
6,064 |
|
|
|
12,054 |
|
Natural gas liquids
|
|
|
3,882 |
|
|
|
2,348 |
|
|
|
1,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain/(loss) on commodity derivatives
|
|
|
341 |
|
|
|
– |
|
|
|
– |
|
Unrealized gain/(loss) on commodity derivatives
|
|
|
(45 |
) |
|
|
– |
|
|
|
– |
|
Gathering income
|
|
|
430 |
|
|
|
419 |
|
|
|
600 |
|
Gain (loss) on sale of oil & gas properties
|
|
|
(122 |
) |
|
|
4,785 |
|
|
|
(5,356 |
) |
Sale of Crude Oil and Condensate
For the twelve months ended December 31, 2013, oil and condensate revenues increased by $7,359,000 relative to the comparable period in 2012. Of the increase, $6,980,000 was due to volume and $379,000 was attributable to realized price. Oil and condensate sales volumes increased by 73 MBbls, consisting of 90 MBbls produced from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013, which was offset by natural production declines in other properties. Average realized price per Bbl increased from $96.00 for the twelve months ended December 31, 2012 to $98.32 for the twelve months ended December 31, 2013.
For the twelve months ended December 31, 2012, oil and condensate revenues increased by $2,161,000 relative to the comparable period in 2011. Of the increase, $2,060,000 was due to volume and $101,000 was attributable to realized price. Oil and condensate sales volumes increased by 21 MBbls, consisting of 53 MBbls produced from new non-operated Eagle Ford properties that were drilled and completed in La Salle County, Texas, which was offset by natural declines in other properties and a decrease of 24 MBbls due to the sale of Madisonville field properties in early 2012. Average realized price per Bbl increased from $94.88 for the twelve months ended December 31, 2011 to $96.00 for the twelve months ended December 31, 2012.
For the twelve months ended December 31, 2013, natural gas revenues increased by $3,650,000 relative to the comparable period in 2012. Of the increase, $892,000 was due to volume and $2,758,000 was attributable to realized price. Natural gas sales volumes increased by 337 MMcf, consisting of 30 MMcf produced from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013 and 600 MMcf produced from new non-operated Eagle Ford wells that were drilled and completed in La Salle County, Texas, which was offset by a decrease in production of 139 MMcf from other properties. Average realized price per Mcf increased from $2.64 for the twelve months ended December 31, 2012 to $3.69 for the twelve months ended December 31, 2013.
For the twelve months ended December 31, 2012, natural gas revenues decreased $5,990,000 relative to the comparable period in 2011. Of the decrease, $2,385,000 was due to volume and $3,605,000 was attributable to price. Natural gas sales volumes decreased by 566 MMcf, primarily consisting of a decrease in production of 467 MMcf from non-operated East Texas properties. Average realized price per Mcf decreased from $4.21 for the twelve months ended December 31, 2011 to $2.64 for the twelve months ended December 31, 2012.
Sale of Natural Gas Liquids
For the twelve months ended December 31, 2013, natural gas liquids revenues increased $1,534,000 relative to the comparable period in 2012. Of the increase, $1,819,000 was due to volume, which was offset by $285,000 attributable to a decrease in realized price. Natural gas liquids sales volumes increased by 58 MBbls, consisting primarily of 49 MBbls produced from new non-operated Eagle Ford wells that were drilled and completed in La Salle County, Texas. Average realized price per Bbl decreased from $31.00 for the twelve months ended December 31, 2012 to $28.88 for the twelve months ended December 31, 2013.
For the twelve months ended December 31, 2012, natural gas liquids revenues increased $695,000 relative to the comparable period in 2011. Of the increase, $1,695,000 was due to volume, which was offset by $1,000,000 attributable to a decrease in realized price. Natural gas liquids sales volumes increased by 39 MBbls, consisting of 41 MBbls produced from new non-operated Eagle Ford wells that were drilled and completed in La Salle County, Texas, which was offset by natural declines in other properties. Average realized price per Bbl decreased from $44.20 for the twelve months ended December 31, 2011 to $31.00 for the twelve months ended December 31, 2012.
During the twelve months ended December 31, 2013, Oak Valley recorded a net gain on derivative contracts of $296,000, consisting of net settled gains of $341,000 and mark-to-market losses of $45,000. Oak Valley was not a party to any derivative contracts during the twelve months ended December 31, 2012 or 2011. Therefore, there is no net gain (loss) on derivative contracts recorded during those comparable periods.
|
|
Twelve Months Ended
December 31,
|
|
|
|
(in thousands)
|
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
Lease operating expenses
|
|
$ |
8,426 |
|
|
$ |
6,212 |
|
|
$ |
7,460 |
|
Severance taxes
|
|
|
1,225 |
|
|
|
608 |
|
|
|
835 |
|
Re-engineering and workover expenses
|
|
|
342 |
|
|
|
570 |
|
|
|
718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE per BOE*
|
|
$ |
10.47 |
|
|
$ |
10.49 |
|
|
$ |
11.97 |
|
Severance taxes as a percent of oil, natural gas, and natural gas liquids revenue
|
|
|
4.13 |
% |
|
|
3.56 |
% |
|
|
4.13 |
% |
* Excludes ad valorem taxes and accretion expense related to the asset retirement obligation.
LOE includes all costs incurred to operate wells and related facilities for both operated and non-operated properties. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE includes product marketing and transportation fees, insurance, ad valorem taxes, accretion expense related to asset retirement obligations, and overhead charges provided for in operating agreements. Ad valorem taxes included in LOE for the twelve months ended December 31, 2013, 2012 and 2011 were $494,000, $271,000 and $300,000, respectively.
LOE increased by $2,214,000 for the twelve months ended December 31, 2013 relative to the comparable period in 2012. The increase in LOE was primarily due to the Operated Eagle Ford Asset Acquisition properties that were acquired during 2013. On a unit-of-production basis, LOE, excluding ad valorem taxes and accretion expense, has remained relatively consistent, decreasing by $0.02 per BOE from $10.49 in 2012 to $10.47 in 2013. Ad valorem taxes in 2013 increased relative to the comparable period in 2012 by $223,000 due to higher assessed property values.
LOE decreased by $1,248,000 for the twelve months ended December 31, 2012 relative to the comparable period in 2011. The decrease in LOE was due to fewer wells with high operating costs. On a unit-of-production basis, LOE, excluding ad valorem costs and accretion expense, decreased by approximately 12%, or $1.48. This decrease is a result of a shift in production contributed by older conventional wells in favor of newer and relatively more cost effective non-operated Eagle Ford wells.
Severance taxes increased by $617,000 to $1,225,000 for the twelve months ended December 31, 2013 relative to the comparable period in 2012. The increase in severance taxes was primarily due to production from Operated Eagle Ford Asset Acquisition properties that were acquired in the second half of 2013. As a percentage of revenues from oil, natural gas, and natural gas liquids, severance taxes increased from 3.6% to 4.1%. This increase is attributable to the Operated Eagle Ford Asset Acquisition, which added a significant amount of production from wells that produce primarily oil and are not subject to tax exemptions, whereas in 2012, a significant amount of new production was from high-cost gas wells that qualify for full or partial severance tax exemptions.
Severance taxes decreased by $227,000 to $608,000 for the twelve months ended December 31, 2012 relative to the comparable period in 2011. The decrease in severance taxes was due to decreases in sale volumes, realized prices for natural gas, and the number of wells qualifying for partial or full severance tax exemptions. As a percentage of revenues from oil, natural gas and natural gas liquids, severance taxes decreased from 4.1% to 3.6%.
Re-engineering and Workovers
Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.
Re-engineering and workover expenses decreased from approximately $570,000 to $342,000 during the twelve months ended December 31, 2013 relative to the comparable period in 2012. During 2013, Oak Valley devoted less capital to re-engineering and workover projects and more effort towards integrating the Operated Eagle Ford Asset Acquisition into its operations and developing an appropriate drilling program.
Re-engineering and workover expenses decreased from approximately $718,000 to $570,000 during the twelve months ended December 31, 2012 relative to the comparable period in 2011. During 2012, Oak Valley sold several properties which previously incurred re-engineering and workover costs in the prior year.
General and Administrative Expenses
G&A expenses primarily consist of overhead expenses, employee remuneration, and professional and consulting fees.
G&A expenses increased by $4,470,000 from approximately $3,280,000 to $7,750,000 for the twelve months ended December 31, 2012 relative to the comparable period in 2013. The increase was due to greater headcount and other administrative expenses related to the December 2012 formation and capitalization of Oak Valley. In addition, $1,008,000 of professional fees and other costs associated with the Operated Eagle Ford Asset Acquisition was incurred in 2013.
G&A expenses remained relatively consistent from the twelve months ended December 31, 2011 to the twelve months ended December 31, 2012, increasing by $138,000 from $3,142,000 in 2011 to $3,280,000 in 2012.
Depreciation, Depletion and Amortization and Impairment Expense
Oak Valley was capitalized on December 21, 2012, and acquired certain subsidiaries in exchange for equity as part of a larger transaction. In accordance with GAAP, this transaction was treated as a common control transaction. As such, Oak Valley was required to report the historical results of operations and financial position for the consolidated subsidiaries and retain the historical cost basis for their assets even though such historical cost bases were in excess of the valuation agreed upon by members at the time of capitalization. This GAAP requirement results in the reporting of higher DD&A provisions and significant impairments, both in 2013 and 2012, than would have been
reported otherwise had the properties been recorded at the agreed upon valuation or fair value. As of December 31, 2013, the net book value had been reduced to less than the Equity Valuation through DD&A expense and impairments calculated in accordance with GAAP.
|
|
Twelve Months Ended
December 31,
|
|
|
|
(in thousands)
|
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
DD&A
|
|
$ |
17,111 |
|
|
$ |
12,192 |
|
|
$ |
16,236 |
|
Impairment
|
|
|
12,298 |
|
|
|
52,475 |
|
|
|
34,294 |
|
DD&A per BOE
|
|
$ |
23.22 |
|
|
$ |
22.20 |
|
|
$ |
27.83 |
|
Depreciation, Depletion and Amortization
DD&A increased by $4,919,000, or 40%, due to higher capitalized property costs and increased production during the twelve months ended December 31, 2013 relative to the comparable period in 2012. Capitalized property costs increased due to (i) the Operated Eagle Ford Asset Acquisition that occurred in the second half of 2013; (ii) costs incurred related to the Eagle Ford drilling program; and (iii) drilling activity on Oak Valley’s non-operated Eagle Ford property. On a unit-of-production basis, DD&A increased from $22.20 per BOE during 2012 to $23.22 per BOE during 2013.
DD&A decreased by $4,044,000, or 25%, due to lower capitalized property costs during the twelve months ended December 31, 2012 relative to the comparable period in 2011. Capitalized costs decreased due to the impairment of certain proved properties during 2011. On a unit-of-production basis, DD&A per BOE decreased from $27.83 during 2011 to $22.20 during 2012.
During the twelve months ended December 31, 2013, Oak Valley incurred impairment charges of $12,298,000, which consisted of $2,481,000 on unproved properties and $9,817,000 on proved properties. The impaired unproved properties primarily consisted of acreage throughout Oklahoma and in Milam County, Texas. The impairment on proved properties resulted from capitalized costs in excess of the fair market value for Oak Valley’s non-operated Eagle Ford property, its Milam County property and one of its East Texas properties.
During 2012, Oak Valley had impairment charges of approximately $52,475,000, which consisted of $8,567,000 on unproved properties and $43,908,000 on proved properties. The impairments on the unproved properties resulted primarily from leases that expired on acreage or acreage that had a cost basis in excess of its fair value in Madison, Zapata and Caldwell counties in Texas. The proved property impairments primarily resulted from capitalized drilling, leasehold, and tangible equipment costs that were in excess of the fair market value on Oak Valley’s non-operated East Texas property and the Red Oak Norris field in Oklahoma.
During 2011, Oak Valley had impairment charges of approximately $34,294,000, which consisted of $18,894,000 on unproved properties and $15,400,000 on proved properties. The impairments on unproved properties resulted primarily from leases that expired on acreage or acreage that had a cost basis in excess of its fair value in Zapata County, Texas. The proved property impairments primarily resulted from capitalized drilling, leasehold and tangible equipment costs that were in excess of the fair market value on Oak Valley’s operated properties in Zapata County, Texas and Caddo Parish, Louisiana.
Interest expense includes commitment fees, amortization of deferred financing costs, and interest on outstanding indebtedness. Debt outstanding as of December 31, 2013 and 2012 was $10,825,000. The debt outstanding as of December 31, 2011 was $5,192,000.
Interest expense increased from $280,000 for the twelve months ended December 31, 2012 to $487,000 for the twelve months ended December 31, 2013. The $207,000 increase in interest expense is due to borrowings during 2012 that remained outstanding throughout 2013, higher commitment fees for the second half of 2013 as a result of a larger unused borrowing base during the second half of 2013 as well as higher amortization of deferred financing costs.
Interest expense increased from $231,000 for the twelve months ended December 31, 2011 to $280,000 for the twelve months ended December 31, 2012. The $49,000 increase in interest expense is due to increased borrowings during 2012.
Oak Valley is a disregarded entity for federal and state income tax purposes and therefore does not pay or accrue for such taxes.
Liquidity and Capital Resources
Oak Valley expects to finance future acquisition, development and exploration activities through available working capital, cash flows from operating activities, borrowings under its credit facility, sale of non-strategic assets, various means of corporate and project financing, and through the issuance of additional debt and/or equity securities. In addition, it may continue to partially finance its drilling activities through the sale of participations to industry partners or financial institutions, and could structure such arrangements on a promoted basis, whereby Oak Valley may earn working interests in reserves and production greater than its proportionate capital costs. Financing activities during the six months ended June 30, 2014 used $102,000 for deferred financing costs and during the comparable period in 2013 provided $68,845,000 in equity contributions offset by
$41,000 for deferred financing costs. Financing activities for the years ended December 31, 2013, 2012, and 2011 provided $107,530,000, $24,790,000 and $13,686,000 in equity contributions, respectively. For the year ended December 31, 2012, Oak Valley distributed $1,187,000 of members’ capital to its former managers pursuant to severance agreements. For the year ended December 31, 2012, financing activities resulted in a net increase in debt of $5,633,000, while during the same period in 2011, Oak Valley had a net decrease in debt of $1,308,000.
Senior Secured Revolving Credit Facility
At June 30, 2014, Oak Valley had a borrowing base of $44,500,000 with available borrowing capacity of $33,375,000 under its credit facility. The borrowing base is reviewed and re-determined in May and November of each year.
Cash Flows from Operating Activities
For the six months ended June 30, 2014, net cash provided by operating activities was $36,140,000. For the same period during 2013, Oak Valley used net cash of $955,000 in operating activities. For the twelve months ended December 31, 2013, 2012 and 2011, net cash provided by operating activities was $15,282,000, $14,985,000 and $10,162,000, respectively. The year-over-year increases in operating cash flows were directly attributable to increased production and positive moves in commodity pricing. Oak Valley believes that it has sufficient liquidity and capital resources to execute its business plan over the next twelve months and for the foreseeable future. Oak
Valley expects to fund its planned capital program though its existing credit facility, working capital, previously committed equity contributions and projected cash flows.
Cash Flows from Investing Activities
Cash applied to oil and gas properties for the six months ended June 30, 2014 and 2013 was $29,197,000 and $13,726,000, respectively. Cash applied to other non-oil and gas property fixed assets for the six months ended June 30, 2014 and 2013 was $229,000 and $387,000, respectively. For the six months ended June 30, 2013, Oak Valley also received $487,000 from the sale of oil and gas properties.
Cash applied to oil and gas properties for the twelve months ended December 31, 2013, 2012 and 2011 was $31,162,000, $39,433,000 and $21,506,000, respectively. During 2013, Oak Valley also used $86,687,000 for the acquisition of its operated Eagle Ford property. Cash applied to other non-oil and gas property fixed assets for the twelve months ended December 31, 2013, 2012 and 2011 was $678,000, $97,000 and $77,000, respectively. In 2013, Oak Valley received $923,000 of insurance proceeds from a well control issue on its non-operated Eagle Ford property. For the
twelve months ended December 31, 2013, 2012 and 2011, Oak Valley received proceeds from the sale of oil and gas properties of $488,000, $9,976,000 and $2,137,000, respectively.
Hedging commodity prices for a portion of Oak Valley’s production is a fundamental part of Oak Valley’s financial management strategy. Oak Valley does not engage in speculative commodity trading activities and does not hedge all available or anticipated quantities of its production. In implementing its hedging strategy, Oak Valley seeks to:
●
|
effectively manage cash flow to minimize price volatility and generate internal funds available for operations, capital development projects, and additional acquisitions; and
|
●
|
ensure its ability to support its exploration activities as well as administrative and debt service obligations.
|
Oak Valley seeks to reduce its sensitivity to oil and gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions which may include fixed-price swaps, price collars, put and other derivatives. Oak Valley believes its hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations.
The following is a summary of Oak Valley’s current oil and gas commodity derivative contracts as of June 30, 2014.
|
|
|
|
|
|
|
|
|
July 2014 – December 2014
|
|
Swap
|
|
Crude Oil
|
|
30,000
|
|
$93.85
|
July 2014 – December 2014
|
|
Swap
|
|
Crude Oil
|
|
30,000
|
|
$95.65
|
July 2014 – December 2014
|
|
Swap
|
|
Crude Oil
|
|
9,600
|
|
$100.05
|
July 2014 – December 2014
|
|
Swap
|
|
Crude Oil
|
|
31,200
|
|
$98.55
|
July 2014 – December 2014
|
|
Swap
|
|
Crude Oil
|
|
32,400
|
|
$98.00
|
January 2015 – June 2015
|
|
Swap
|
|
Crude Oil
|
|
21,000
|
|
$91.50
|
January 2015 – December 2015
|
|
Swap
|
|
Crude Oil
|
|
66,000
|
|
$95.10
|
July 2014 – December 2014
|
|
Swap
|
|
Nat. Gas
|
|
51,480
|
|
$4.600
|
July 2014 – December 2014
|
|
Swap
|
|
Nat. Gas
|
|
300,000
|
|
$4.550
|
July 2014 – March 2015
|
|
Swap
|
|
Nat. Gas
|
|
375,000
|
|
$4.300
|
July 2014 – March 2015
|
|
Swap
|
|
Nat. Gas
|
|
450,000
|
|
$4.175
|
Fair Market Value of Commodity Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
– |
|
|
$ |
7,000 |
|
|
$ |
154,000 |
|
|
|
– |
|
|
|
– |
|
|
|
255,000 |
|
Non-current
|
|
|
6,000 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(1,108,000 |
) |
|
|
(165,000 |
) |
|
|
(105,000 |
) |
|
|
(67,000 |
) |
|
|
(17,000 |
) |
|
|
– |
|
Non-Current
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(27,000 |
) |
|
|
– |
|
|
|
– |
|
Assets and liabilities are netted within each commodity on the balance sheet as all contracts are with the same counterparty. For the balances without netting, refer to Note 4 – “Derivative Financial Instruments” in the Notes to the Historical Consolidated Financial Statements of Oak Valley contained elsewhere in this proxy statement.
Estimating the fair value of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices which, although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of Oak Valley’s commodity derivatives. Oak Valley currently obtains fair value positions from its counterparties and compares that value to the calculated value provided by its outside commodity derivative consultant. Oak Valley believes that the practice of comparing the consultant’s value to that of Oak Valley’s counterparties, who are more specialized and knowledgeable
in preparing these complex calculations, reduces the risk of error and approximates the fair value of the contracts, as the fair value obtained from Oak Valley’s counterparties would be the cost to Oak Valley to terminate a contract at that point in time.
Commitments and Contingencies
Oak Valley has the following contractual obligations and commitments as of June 30, 2014 (in thousands):
|
|
Debt
|
|
|
Drilling Commitments
|
|
|
Liability for Commodity Derivatives
|
|
|
Operating Leases
|
|
|
Asset Retirement Obligations
|
|
2014
|
|
$ |
– |
|
|
$ |
2,845 |
|
|
$ |
975 |
|
|
$ |
169 |
|
|
$ |
67 |
|
2015
|
|
|
– |
|
|
|
– |
|
|
|
328 |
|
|
|
590 |
|
|
|
– |
|
2016
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
600 |
|
|
|
– |
|
2017
|
|
|
10,825 |
|
|
|
– |
|
|
|
– |
|
|
|
609 |
|
|
|
2,162 |
|
2018
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
619 |
|
|
|
61 |
|
Thereafter
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
575 |
|
|
|
870 |
|
Total
|
|
$ |
10,825 |
|
|
$ |
2,845 |
|
|
$ |
1,303 |
|
|
$ |
3,162 |
|
|
$ |
3,160 |
|
Oak Valley has reserved gathering and processing capacity in a pipeline and has a volume commitment whereby it pays the owner of the pipeline a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity. The rate and terms under this purchasing and processing contract expire on June 1, 2021.
Off-Balance Sheet Arrangements
Oak Valley has no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees.
Quantitative and Qualitative Disclosures About Market Risk of Oak Valley
Commodities. Oak Valley is exposed to market risk from changes in commodity prices. In the normal course of business, Oak Valley enters into derivative transactions, including commodity price collars, swaps and floors to mitigate its exposure to commodity price movements. Oak Valley does not participate in these transactions for trading or speculative purposes. While the use of these arrangements may limit the benefit to Oak Valley of increases in the prices of oil and natural gas, it also limits the downside risk of adverse price movements.
Interest rates. Oak Valley is exposed to financial risk from changes in future interest rates to the extent that it incurs future indebtedness. As of June 30, 2014, Oak Valley had outstanding indebtedness under its credit facility of $10,825,000, which matures in June 2017. The credit facility provides for a variable interest rate. In the event interest rates rise significantly, and Oak Valley incurs future indebtedness without mitigating or fixing future interest rates, Oak Valley’s interest expense will increase in accordance with any future borrowings and at rates in effect at the time of those borrowings.
OAK VALLEY EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
The executive officers for Oak Valley’s fiscal years ended December 31, 2012 and 2013, and who are described in this Compensation Discussion and Analysis section, are:
●
|
Timothy D. Merrifield, Executive Vice President, Geology and Geophysics
|
●
|
Steven C. Collins, Executive Vice President, Completions and Operations
|
Philosophy and Objectives of Oak Valley’s Executive Compensation Program
The primary objectives of Oak Valley’s executive compensation program are to (i) motivate the executive officers to help achieve Oak Valley’s long- and short-term goals by rewarding superior individual and company performance and (ii) retain Oak Valley’s experienced and successful leadership team and continue to recruit high quality talent by providing compensation that is competitive with the companies with which Oak Valley competes for executive talent.
Oak Valley has been a limited liability company since its inception in December 2012. Because it is not a typical corporation with stock option, restricted stock award or similar plans, the compensation paid to the executive officers has primarily been cash salaries and cash bonuses.
In addition, Oak Valley has a class of membership interests called Class C Units that permit the holders thereof to receive a portion of Oak Valley’s profits which are in excess of certain target investment returns. Oak Valley has issued all of its Class C Units to OVM, to enable OVM to issue corresponding profits units to employees of Oak Valley. The profits units are non-voting and do not entitle the holder to any rights with respect to the limited liability company agreements of Oak Valley or OVM.
A portion of the profits units were issued to the executive officers below with one of two vesting scenarios, either (i) 40% upon date of grant in September 2013 and 2.5% monthly thereafter or (ii) upon an Exit Event. An “Exit Event” means the sale of Oak Valley, in one transaction or a series of related transactions, whether structured as (i) a sale or other transfer of all or substantially all of the equity interests of Oak Valley (including by way of merger, consolidation, share exchange, or similar transaction), (ii) the sale or other transfer of all or substantially all of the assets of Oak Valley, or (iii) a combination of any of the foregoing. The exchange will not constitute an Exit Event. In the event an employee terminates his or her employment with Oak Valley prior to vesting, the unvested profits units will be forfeited by the holder.
Oak Valley is currently re-evaluating the executive compensation structures and systems that it will provide for its executive officers, with attention to instituting equity awards under the 2014 Plan, if approved, benchmarking compensation through the use of surveys and the potential services of an outside consultant, and revising its cash and bonus programs to base awards on market data and performance goals, with attention to encouraging long-term sustained performance.
Summary Compensation Table
Name and Principal Position
|
|
|
|
|
|
|
|
|
|
All Other Compensation (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
$ |
204,839 |
|
|
$ |
108,000 |
|
|
$ |
– |
|
|
$ |
312,839 |
|
President and CEO |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Timothy D. Merrifield
|
|
2013
|
|
$ |
185,833 |
|
|
$ |
95,000 |
|
|
$ |
7,100 |
|
|
$ |
287,933 |
|
Executive Vice President |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Steven C. Collins
|
|
2013
|
|
$ |
179,167 |
|
|
$ |
72,000 |
|
|
$ |
6,700 |
|
|
$ |
257,867 |
|
Executive Vice President |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Consists of matching contributions to the 401(k) plan.
BUSINESS OF EARTHSTONE
Earthstone Energy, Inc. was incorporated in Delaware in 1969 as Basic Earth Science Systems, Inc. The name was changed in 2010 to Earthstone Energy, Inc. Earthstone is a growth-oriented independent oil and gas exploration and production company primarily engaged in the exploration, development and production of oil and natural gas properties. It has an established production base that generates positive cash flow from operating activities and profits. Earthstone’s operating activities are concentrated in the North Dakota and Montana portions of the Williston Basin and south Texas. As of March 31, 2014, Earthstone’s estimated net proved oil and natural gas reserves were 2,554,000 Bbls of oil and condensate and 3,413,000 Mcfs of natural gas.
Earthstone’s current primary operational focus is in the Montana and North Dakota portions of the Williston Basin. This oil rich basin has been allocated the majority of Earthstone’s capital expenditure budget. Earthstone has been involved in the Williston Basin since the early 1980s and only in south Texas does it have a longer history. Accordingly, Earthstone has a significant understanding of, and exposure to, both the local geology and geologic processes.
In 2013, Earthstone began a re-evaluation of the West Cole Unit and the West Cole North Unit (Units), its long-held, waterflood properties in Webb County, Texas. As a result, it identified eleven potential new locations that could prove productive, and has begun to evaluate three of these locations. If these three wells prove to be economic producers, the eight remaining locations could be drilled.
In addition to the Williston Basin and south Texas, Earthstone is pursuing an exploration project in the Nebraska portion of the Denver-Julesburg (DJ) Basin. While the Nebraska panhandle has long been a producing region with a high density of shallow wells, it has only been sparsely explored in its deeper horizons. Based on 3-D seismic data, Earthstone had identified eight areas of interest, or prospects, within the area. After drilling a dry hole in 2013 on these prospects, Earthstone will re-evaluate its seismic interpretation, the remaining prospects and other areas within Cheyenne County, Nebraska that may be of interest. Earthstone is, and will be, the operator of wells drilled in this project.
In 2013, non-operated drilling projects comprised the majority of Earthstone’s capital expenditures. In 2014, this trend will continue with respect to Earthstone’s historic properties, despite the operated Nebraska project, due to the size of Earthstone’s Bakken activity. Earthstone expects to continue to emphasize the acquisition of producing properties. However, these efforts are typically not predictable and are opportunistic in nature.
Historically, Earthstone has not placed emphasis on acquiring new, large, non-producing acreage positions. In 2014, as existing inventory of North Dakota acreage is developed, it could shift capital expenditure dollars into undeveloped acreage in this area.
Earthstone is focusing on keeping its operating costs under control. However, it expects rig and vendor service costs to continue to escalate, especially in North Dakota and Montana, due to high demand. Maintaining a low overhead structure is fundamental to Earthstone’s cost containment. However, over the last two years, Earthstone has expanded and/or restructured its staff to increase its operational capability in preparation for Nebraska, to more closely monitor and maintain its Bakken acreage and to comply with increased regulation. Earthstone is using and will continue to use the services of independent consultants and contractors to perform various professional services, and believes that this use of third-party service providers enhances its ability to contain general and administrative expenses.
The expectations set forth above may be altered by subsequent events or other, more attractive opportunities that may present themselves in the future. In particular, if the exchange is consummated, as Oak Valley management and properties are brought into Earthstone, capital spending priorities are likely to be reassessed and realigned.
Williston Basin. The Williston Basin continues to be Earthstone’s highest area of activity, both in terms of cash flow from existing properties and expenditures for drilling efforts as well as the acquisition of producing properties. There are several areas within the Williston Basin where drilling operations are expected to commence and/or continue in 2014. These areas are the Banks and Indian Hill Fields in McKenzie County, North Dakota. While not a primary area of focus, Earthstone continues to deploy capital in areas beyond the Williston Basin to exploit reserve potential both on existing properties and new prospects.
Banks Field — McKenzie County, North Dakota. In the fiscal year ended March 31, 2014, 32 horizontal Bakken/Three Forks wells in which Earthstone has an interest were completed and brought onto production. All of these wells are being operated by Statoil. Drilling commenced on an additional seven wells in which Earthstone has interests, but as of March 31, 2014, these wells have not been completed. All seven wells are considered to be Proved Undeveloped, per SEC criteria. Based on information available at this time, Earthstone anticipates an additional 99 wells in this prospect.
Indian Hill Field & Camel Butte Fields — McKenzie County, North Dakota. Earthstone currently has an interest in two horizontal Bakken/Three Forks wells in the Indian Hill Field and three horizontal Bakken/Three Forks wells in the Camel Butte Field. Along with Continental Resources, Inc., drilling has commenced on five horizontal Bakken/Three Forks wells, but as of March 31, 2014, these wells have not been completed. ConocoPhillips drilled and completed one well in the Camel Butte Field. These five Continental wells are considered to be Proved Undeveloped, per SEC criteria.
Elm Coulee Field — Richland County, Montana. Earthstone currently has an interest in four horizontal Bakken wells in the Elm Coulee Field and several, legacy, vertical wells that hold Bakken acreage. Most areas in the Elm Coulee Field contain two wells per spacing unit. Now that this field is reaching maturity, it is not unreasonable to expect select areas of this field to be developed with three wells per spacing unit.
Bailey, Champion & Murphy Creek Fields — Dunn County, North Dakota. Earthstone currently has an interest in nine producing horizontal Bakken wells.
Mondak Field — McKenzie County, North Dakota. Earthstone currently has an interest in three horizontal Bakken wells in the Mondak Field. This acreage is currently developed for one well per spacing unit. However, Earthstone anticipates that this acreage will be developed at higher densities in the future.
Divide County, North Dakota — Sheridan County, Montana. In both of these counties, Earthstone holds undeveloped acreage by virtue of existing vertical wells. The acreage is probable for Bakken or Three Forks development. In 2013, several companies have drilled horizontal Bakken or Three Forks wells in the area, albeit with limited success. In 2012, Earthstone acquired three producing vertical wells, along with each well’s associated acreage. Earthstone participated with Vess Oil Corporation in the drilling of a horizontal Ratcliffe well in the Rush Mountain Field of Sheridan County with a 10% working interest. Given cost overruns by Vess, the well was less than successful. Vess has the right to propose additional horizontal Ratcliffe wells but so far has declined to do so.
Permo-Penn Play, Nebraska, DJ Basin. Earthstone has acquired approximately 70 square miles of 3-D seismic data and 30,000 gross acres of leasehold, primarily in Cheyenne County. The deeper formations in this area are relatively unexplored, in some cases less than one deep well per township. However, by Williston Basin standards, these wells are much shallower and are inexpensive to drill. Earthstone’s initial effort was a vertical well that resulted in a dry hole. Going forward, as better knowledge is gained of the deposits, horizontal drilling may be incorporated into exploration efforts. Earthstone is the operator and has a 45% working interest in this venture.
During the year ended March 31, 2014, proved reserves in BOE and PV-10 increased approximately 7% and 43%, respectively (from March 31, 2013). Additional information about Earthstone reserves and the calculation of reserves may be referenced in “Reserves.”
Earthstone is continually evaluating other drilling and acquisition opportunities for possible participation. Generally, at any one time, Earthstone is engaged in various stages of evaluation in connection with one or more drilling or acquisition opportunities. Unless required by applicable law, Earthstone’s policy is generally not to disclose the specifics of any such opportunity until such time as that transaction is finalized and a definitive agreement has been entered into and then, only when such transaction is material to the overall business. Similarly, Earthstone does not speculate on the outcome of such ventures until the drilling, production or other results are available and have been verified.
Earthstone may alter or vary all or part of these contemplated activities based upon changes in circumstances, including, but not limited to, unforeseen opportunities, inability to negotiate favorable acquisitions, farmouts, joint ventures, or divestitures, commodity prices, lack of cash flow, lack of funding and/or other events which are not able to anticipate.
Segment Information and Major Customers
Industry segment. Earthstone is engaged only in the upstream segment of the oil and gas industry, which comprises exploration, production, and development for and of crude oil and natural gas. While Earthstone operates a small number of oil wells, it does not own or operate any gas gathering or processing plant facilities, nor does it possess sufficient volume on any pipeline to market its product to end users. All of its operations are conducted in the United States. Consequently, it presently reports under a single industry segment.
Markets. Earthstone is a small company and, as such, has no impact on the market for its product and little control over the price received. Markets for crude oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond Earthstone’s control, including other sources of production, competitive fuels and proximity and capacity of pipelines or other means of transportation, seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies.
Substantially all of Earthstone’s natural gas production is sold at prevailing wellhead gas prices, subject to additional charges customary to an area.
The oil and gas business is not generally seasonal in nature, although unusual weather extremes for extended periods may increase or decrease demand for oil and natural gas products temporarily. Additionally, catastrophic events, such as hurricanes or other supply disruptions, may temporarily increase the demand for oil and gas supplies from areas unaffected by supply disruptions. Such events and their impacts on oil and gas commodity prices may cause fluctuations in quarterly or annual revenue and earnings. Also, because of the location of many of Earthstone’s properties in Montana and North Dakota, severe weather conditions, especially in the winter months, could have a material adverse effect on its operations and cash flow.
Major Customers. During the year ended March 31, 2014, approximately 20% of Earthstone’s oil and natural gas production revenues were received from sales to seven purchasers (compared to 35% to six purchasers in the previous fiscal year). The remaining 80% of its revenue was received from non-operated properties where Earthstone had no direct contact with the purchaser. On these properties, Earthstone’s portion of the product is marketed on its behalf by the 25 different companies that operate these wells. These 25 companies may market to one or more of the same purchasers to whom Earthstone sells directly. Therefore, Earthstone is unable to ascertain the total extent of combined purchaser concentration. Earthstone estimates that, in the event of the bankruptcy of any one of these purchasers, or purchasers on non-operated properties, the reduction in
annual revenue would be less than 10%. Earthstone does not expect that the loss of any one of these purchasers would cause a material adverse impact on its results of operations, as alternative markets for oil and natural gas production are readily available.
The oil and gas industry is a highly competitive and speculative business. Earthstone encounters strong competition from major and independent oil companies in all phases of its operations. In this arena, it must compete with many companies having significantly greater financial resources and larger technical staffs. Furthermore, as a small company with limited market liquidity, Earthstone competes with larger companies that have greater, more efficient access to the capital markets. Finally, as “resource plays” have evolved, the industry has become much more capital intensive, and Earthstone’s exposure to opportunities has been diminished due to its limited resources.
As of March 31, 2014, Earthstone had 12 full-time, three part-time employees and four part-time contractors. Five of these employees are primarily field laborers and are located at Earthstone’s subsidiary’s (Basic Petroleum Services, Inc.) field office in Bruni, Texas, 45 miles southeast of Laredo, Texas. In addition, in other areas, Earthstone has five contract field workers on a part-time retainer basis. Earthstone believes its employee and contractor relations are good.
General. Earthstone is affected in varying degrees by federal, state, regional and local laws and regulations, including, but not limited to, laws governing well spacing, air emissions, water discharges, reporting requirements, endangered species, marketing, prices, taxes, allowable rates of production and the plugging and abandonment of wells, the subsequent rehabilitation of the well site locations, occupational health and safety, control of toxic substances, and other matters involving environmental protection. These laws are continually changing and, in general, are becoming more restrictive. Earthstone has expended, and expects to expend in the future, significant funds to comply with such laws and regulations. Changes to current local, state or federal laws and regulations in the jurisdictions where Earthstone operates could require additional capital expenditures and result in
an increase in costs. Although Earthstone is unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could impact the economics of its projects.
Environmental matters. Earthstone is subject to various federal, state, regional and local laws and regulations related to the discharge of materials into, and the protection of, the environment. These laws and regulations, among other things, may impose a liability on the owner or the lessee for the cost of pollution cleanup resulting from operations, subject the owner or lessee to a liability for pollution damages, require the suspension or cessation of operations in affected areas and impose restrictions on injection into subsurface formations in order to prevent the contamination of ground water.
Earthstone engages in hydraulic fracturing activities. Each state has comprehensive laws and regulations to provide for safe well construction practices and operations to ensure the protection of drinking water sources. To its knowledge, Earthstone is, and remains, in compliance with all federal, state and local provisions which have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. With regard to the magnitude of its use of hydraulic fracturing of oil and gas wells, Earthstone holds a minority interest in a number of wells that are under the management and control of far larger companies that apply various stimulation strategies. Earthstone’s ownership varies on these new drilling projects from 0.1% to 6.5% interest depending on the specific well. With these small interests, if a containment failure were to occur on a single well,
it is not likely that the event would have a material financial or operational impact on Earthstone.
Potential environmental effects may also arise from the use of disposal and injector wells. Earthstone holds a working interest in five disposal and seven injector wells, nine of which it operates, the remaining of which are owned and operated by third parties whose disposal practices are outside of Earthstone’s control.
Although environmental requirements do have a substantial impact upon the energy industry, these requirements do not appear to affect Earthstone any differently than other companies in this industry that operate in a given geographic area. Earthstone is not aware of any environmental claims which could have a material impact upon its financial condition, results of operations, or cash flows. Such regulations have increased the resources required and costs associated with planning, designing, drilling, operating, installing and abandoning oil and natural gas wells and facilities. Earthstone maintains insurance coverage that it believes is customary in the industry.
Producing Properties: Location and Impact
As of March 31, 2014, Earthstone owned a working interest in 157 gross producing oil wells, three gross producing gas wells, six disposal wells and seven injector wells.
Productive Wells
|
|
Gross Wells
|
|
|
Net Wells
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
North Dakota
|
|
|
99 |
|
|
|
2 |
|
|
|
10.77 |
|
|
|
0.13 |
|
Montana
|
|
|
28 |
|
|
|
— |
|
|
|
11.98 |
|
|
|
— |
|
Texas
|
|
|
27 |
|
|
|
— |
|
|
|
24.10 |
|
|
|
— |
|
Louisiana
|
|
|
2 |
|
|
|
— |
|
|
|
0.11 |
|
|
|
— |
|
Colorado
|
|
|
— |
|
|
|
1 |
|
|
|
— |
|
|
|
0.05 |
|
Wyoming
|
|
|
1 |
|
|
|
— |
|
|
|
0.47 |
|
|
|
— |
|
Total
|
|
|
157 |
|
|
|
3 |
|
|
|
47.43 |
|
|
|
0.18 |
|
Specific production data relative to Earthstone’s oil and natural gas producing properties can be found in the “Selected Financial Information of Earthstone.”
As of March 31, 2014, Earthstone’s estimated proved oil and natural gas reserves in barrels of oil equivalent (“BOE”) was 3,123,000, a 7% increase from the March 31, 2013 estimated proved oil and natural gas reserves of 2,921,000 BOE. This increase primarily reflects the addition of new wells.
Geographically, Earthstone’s reported reserves are located in two primary areas: the Williston Basin in North Dakota and Montana and south Texas. While Earthstone holds interests in producing wells outside of these two primary locations, no reserves are reported for such properties in the following table due to their insignificance. The following table summarizes the estimated proved developed oil and natural gas reserves for these two areas as of March 31, 2014:
Estimated Proved Developed Oil and Gas Reserves by Area
|
|
Net Oil
|
|
|
Net Gas
|
|
|
|
|
|
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
BOE
|
|
|
%
|
|
Williston Basin
|
|
|
1,093,000 |
|
|
|
1,773,000 |
|
|
|
1,389,000 |
|
|
|
76.2 |
% |
South Texas/Onshore Gulf Coast
|
|
|
433,000 |
|
|
|
— |
|
|
|
433,000 |
|
|
|
23.8 |
% |
Total
|
|
|
1,526,000 |
|
|
|
1,773,000 |
|
|
|
1,822,000 |
|
|
|
100.0 |
% |
Preparation of Proved Reserves Estimates
Earthstone’s policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance. All of Earthstone’s reported oil and natural gas reserves have been estimated as of March 31, 2014 and 2013, by Ryder Scott. Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 75 years. Ryder Scott is employee owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. Ryder Scott has over 80 engineers and geoscientists on its permanent staff. The office of Ryder Scott that prepared Earthstone’s reserve estimates is registered in the state of Texas (License #F-1580). Ryder Scott prepared Earthstone’s reserve estimate
based upon a review of property interests being appraised, historical production, lease operating expenses and price differentials for its wells. Additionally, Earthstone provides its engineer with authorizations for expenditure (“AFEs”), geological and geophysical data, and other engineering data that complies with SEC guidelines for consideration in estimating the underground accumulations of crude oil and natural gas. This information was reviewed by Ray Singleton, President and Chief Executive Officer, to ensure accuracy and completeness of the data prior to and after submission to Ryder Scott. Mr. Singleton received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. In his capacity as an engineer, Mr. Singleton prepared reserve and economic estimates during his employment with both Amoco Production Company and Champlin Petroleum. Mr.
Singleton continued providing economic evaluations for approximately 40 different clients through his engineering consulting firm, Singleton & Associates, from 1982 to 1988, and thereafter for Earthstone Energy, Inc. since his employment in 1988. In addition, Mr. Singleton is currently a member of the Society of Petroleum Engineers. The report of Ryder Scott dated May 9, 2014, which contains further discussions of the reserve estimates and evaluations prepared by Ryder Scott as well as the qualifications of Ryder Scott’s technical personnel responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.3 to Earthstone’s Annual Report on Form 10-K for the year ended March 31, 2014.
Technologies Used in Preparation of Proved Reserves Estimates
All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance methods used are limited to decline curve analysis which utilized extrapolations of historical production and pressure data available through March 31, 2014. The data used in this analysis was obtained from public data sources and was considered sufficient for calculating producing reserves. The proved undeveloped reserves were estimated by the analogy method. The analogy method uses pertinent well data obtained from public data sources that were available through March 31, 2014.
Oil and gas reserves and the estimates of the present value of future net revenues were determined based on prices and costs as prescribed by SEC and the Financial Accounting Standards Board (“FASB”) guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated
in accordance with guidelines established by the SEC and FASB, which require that reserves estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.
The following table sets forth certain information regarding estimates of Earthstone’s oil and gas reserves as of March 31, 2014. All of Earthstone’s reserves are located in the United States.
Estimated Proved Developed and Undeveloped Oil and Gas Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Remaining Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil/Condensate – Bbls
|
|
|
1,526,000
|
|
|
|
―
|
|
|
|
1,028,000
|
|
|
|
2,554,000
|
|
Plant Products – Bbls
|
|
|
―
|
|
|
|
―
|
|
|
|
―
|
|
|
|
―
|
|
Gas – Mcf
|
|
|
1,773,000
|
|
|
|
―
|
|
|
|
1,640,000
|
|
|
|
3,413,000
|
|
Estimated Proved Developed and Undeveloped Oil and Gas Reserves
During 2014, Earthstone had a positive revision of 14,000 BOE, or 1%, from its March 31, 2013 estimated proved undeveloped reserves balance. These revisions resulted primarily from increases in pricing which extended the economic life of the wells. Within portions of Earthstone’s areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in Earthstone’s March 31, 2013 reserve report. The proved undeveloped forecasts in these areas have been adjusted in the Earthstone’s March 31, 2014 reserve report to reflect these well performances. A reconciliation of the change in proved undeveloped reserves during the year ended March 31, 2014 is as follows:
|
|
|
|
Estimated Proved Undeveloped Reserves, beginning of year
|
|
|
1,336,000 |
|
PUD converted to PDP
|
|
|
(506,000 |
) |
PUD added during the year
|
|
|
457,000 |
|
Revisions of previous estimates
|
|
|
14,000 |
|
Estimated Proved Undeveloped Reserves, end of year
|
|
|
1,301,000 |
|
The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this proxy. In addition, estimates of proved reserves are subject to revision to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond Earthstone’s control. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered and
are highly dependent upon the accuracy of the assumptions upon which they are based.
Additional information pertaining to Earthstone’s proved reserves is set forth under the heading “Unaudited Oil and Gas Reserves Information” in the notes to its consolidated financial statements included in this proxy statement.
Oil and Gas Production and Sales Prices
Refer to “Selected Financial Information of Earthstone” for information regarding Earthstone’s net oil and gas production, the average sales price, and the average cost of production per BOE, for the three months ended June 30, 2014 and 2013 and the years ended March 31, 2014 and 2013.
The following table sets forth Earthstone’s gross and net working interests in exploratory and development wells drilled during the years ended March 31, 2014, 2013 and 2012, respectively:
Exploratory and Developmental Wells Drilled
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
1 |
|
|
|
0.45 |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Exploratory
|
|
|
1 |
|
|
|
0.45 |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developmental:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
1.45 |
|
|
|
20 |
|
|
|
0.508 |
|
|
|
18 |
|
|
|
0.74 |
|
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
― |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Developmental
|
|
|
35 |
|
|
|
1.45 |
|
|
|
20 |
|
|
|
0.508 |
|
|
|
18 |
|
|
|
0.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Exploratory and Developmental Wells Drilled
|
|
|
36 |
|
|
|
1.90 |
|
|
|
20 |
|
|
|
0.508 |
|
|
|
18 |
|
|
|
0.74 |
|
Earthstone leases the rights to explore for and produce oil and gas from mineral owners. Leases (quantified in acres) expire after their primary term unless oil or gas production is established. Prior to establishing production, leases are generally considered undeveloped. After production is established, leases are considered developed or “held-by-production.” Earthstone’s acreage is comprised of developed and undeveloped acreage as follows:
Gross and Net Acreage
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Louisiana
|
|
|
687
|
|
|
|
51
|
|
|
|
—
|
|
|
|
—
|
|
Montana
|
|
|
7,053
|
|
|
|
2,090
|
|
|
|
12,472
|
|
|
|
2,557
|
|
Nebraska
|
|
|
—
|
|
|
|
—
|
|
|
|
30,469
|
|
|
|
11,700
|
|
North Dakota
|
|
|
25,315
|
|
|
|
2,572
|
|
|
|
5,809
|
|
|
|
1,614
|
|
Texas
|
|
|
2,807
|
|
|
|
2,464
|
|
|
|
—
|
|
|
|
—
|
|
Utah
|
|
|
—
|
|
|
|
—
|
|
|
|
42,736
|
|
|
|
441
|
|
Wyoming
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped acreage includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of oil and natural gas.
Leasehold Acreage Expirations
A significant portion of Earthstone’s acreage is not currently held by production or held by operations. Unless production in paying quantities is established or operations are commenced on units containing these leases during their terms, the leases will expire. If these leases expire and Earthstone is unable to renew the leases, it will lose its right to participate in the development of the related properties. Drilling plans for these areas are generally in the discretion of third-party operators and are subject to change based on various factors that are beyond Earthstone’s control, such as the availability and cost of capital, equipment, services and personnel; seasonal conditions; regulatory and third-party approvals; oil, natural gas liquids (“NGL”) and natural gas prices; results of title work; gathering system and other transportation constraints; drilling costs and results; and production costs. As of March
31, 2014, Earthstone estimates that it had leases that were not developed that represented 12,204 net acres potentially expiring as follows:
|
|
March 31,
|
|
|
|
(in net acres)
|
|
Future expirations of net acreage:
|
|
|
|
2015
|
|
|
656 |
|
2016
|
|
|
1,715 |
|
2017
|
|
|
1,423 |
|
2018
|
|
|
5,960 |
|
2019
|
|
|
2,206 |
|
Thereafter
|
|
|
244 |
|
Total
|
|
|
12,204 |
|
Earthstone currently leases approximately 7,000 square feet of office space in downtown Denver, Colorado from an independent third party for approximately $9,880 per month plus maintenance fees. The lease term ends on April 30, 2016. For additional information, see Note 7 to the consolidated financial statements for the years ended March 31, 2014 and 2013.
Earthstone is not a party, nor are any of its properties subject, to any pending material legal proceedings. Earthstone knows of no legal proceedings contemplated or threatened against it.
SELECTED FINANCIAL INFORMATION OF EARTHSTONE
The following provides selected financial information and averages for the three months ended June 30, 2014 and 2013 and the years ended March 31, 2014 and 2013. Certain prior year amounts may have been reclassified to conform to the current presentation.
|
|
Three Months Ended
June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,373,000 |
|
|
$ |
3,380,000 |
|
|
$ |
15,633,000 |
|
|
$ |
10,283,000 |
|
|
|
|
841,000 |
|
|
|
202,000 |
|
|
|
1,807,000 |
|
|
|
699,000 |
|
|
|
|
5,214,000 |
|
|
|
3,582,000 |
|
|
|
17,440,000 |
|
|
|
10,982,000 |
|
Total production expense (3)
|
|
|
1,492,000 |
|
|
|
1,144,000 |
|
|
|
3,957,000 |
|
|
|
3,453,000 |
|
|
|
$ |
3,722,000 |
|
|
$ |
2,438,000 |
|
|
$ |
13,483,000 |
|
|
$ |
7,529,000 |
|
Depletion expense
|
|
$ |
1,117,000 |
|
|
$ |
760,000 |
|
|
$ |
3,768,000 |
|
|
$ |
1,951,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volume: (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,742 |
|
|
|
36,967 |
|
|
|
173,880 |
|
|
|
122,655 |
|
|
|
|
66,868 |
|
|
|
28,223 |
|
|
|
189,933 |
|
|
|
107,076 |
|
|
|
|
59,887 |
|
|
|
41,671 |
|
|
|
205,536 |
|
|
|
140,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price: (5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
89.72 |
|
|
$ |
91.43 |
|
|
$ |
89.91 |
|
|
$ |
83.84 |
|
|
|
$ |
12.58 |
|
|
$ |
7.16 |
|
|
$ |
9.51 |
|
|
$ |
6.53 |
|
|
|
$ |
87.06 |
|
|
$ |
85.96 |
|
|
$ |
84.85 |
|
|
$ |
78.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average per BOE: (4)(5)(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
24.91 |
|
|
$ |
27.45 |
|
|
$ |
19.25 |
|
|
$ |
24.58 |
|
|
|
$ |
62.15 |
|
|
$ |
58.51 |
|
|
$ |
65.60 |
|
|
$ |
53.59 |
|
|
|
$ |
18.65 |
|
|
$ |
18.24 |
|
|
$ |
18.33 |
|
|
$ |
13.89 |
|
__________________
(1)
|
Amount includes NGL revenue. For the three months ended June 30, 2014 and 2013, the NGL revenue included in the gas revenue amount is $409,000 and $72,000, respectively. For the years ended March 31, 2014 and 2013, the NGL revenue included in the gas revenue amount is $808,000 and $221,000, respectively.
|
(2)
|
Amount does not include water service and disposal revenue. For the three months ended June 30, 2014, this revenue amount is net of $24,000 in well service and water disposal revenue, which would otherwise total $5,238,000 in revenue, compared to $13,000 well service and water disposal revenue in the respective period ended June 30, 2013 and $3,595,000 in total revenue for the comparable three-month period ended June 30, 2013. For the years ended March 31, 2014 and 2013, this revenue amount is net of $74,000 and $396,000, respectively, in well service and water disposal revenue, which would otherwise total $17,514,000 and $11,378,000, respectively, in revenue.
|
(3)
|
Overall lifting cost (oil and gas production costs, including production taxes and the cost of workovers).
|
(4)
|
Estimates of volumes are inherent in reported volumes to coincide with revenue accruals as a result of the timing of sales information reporting by third-party operators.
|
(5)
|
Averages calculated based upon non-rounded figures.
|
(6)
|
Average gas sales price per Mcf is calculated by dividing total gas and NGL revenue by the gas sales volume per Mcf. For the three months ended June 30, 2014 and 2013, gas sales price per Mcf, exclusive of NGL revenues, was $6.46 per Mcf and $4.61 per Mcf, respectively. For the years ended March 31, 2014 and 2013, gas sales price per Mcf, exclusive of NGL revenues, was $5.26 per Mcf and $4.46 per Mcf, respectively.
|
(7)
|
Per equivalent barrel (6 thousand cubic feet, “Mcf,” of gas is equivalent to 1 barrel, “Bbl,” of oil).
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS OF EARTHSTONE
The following discussion and analysis should be read in conjunction with Earthstone’s financial statements and related notes and the other information appearing in this proxy statement. As used in this proxy statement, unless the context otherwise indicates, references to Earthstone refer to Earthstone Energy, Inc. and its subsidiary collectively.
As an oil and natural gas producer, Earthstone’s revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil and natural gas. Declines in commodity prices will materially and adversely affect Earthstone’s financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that can be produced economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond Earthstone’s control, such as global, political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most
of Earthstone’s production is sold at market prices. Generally, if the commodity indexes fall, the price that Earthstone receives for its production will also decline. Therefore, the amount of revenue that Earthstone realizes is, to a large extent, determined by factors beyond its control.
Liquidity and Capital Resources
Liquidity Outlook. Earthstone’s primary source of funding is the net cash flow from the sale of oil and natural gas production. The profitability and cash flow generated by operations in any particular accounting period will be directly related to: (a) the volume of oil and gas produced and sold, (b) the average realized prices for oil and gas sold, and (c) lifting costs. At the current price of oil, Earthstone believes the cash generated from operations, along with existing cash balances and available line of credit, should enable it to meet its existing and normal recurring obligations during the next year and beyond.
On December 21, 2012, Earthstone entered into a $25 million senior secured revolving bank credit facility (the “Credit Facility”) with the Bank of Oklahoma (“Bank”). The Credit Facility was amended effective September 10, 2013. The current borrowing base on the Credit Facility is $12 million. Among other provisions, the Credit Facility contains certain affirmative and negative covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios.
As of June 30, 2014, there was an outstanding balance of $8 million under the Credit Facility, and Earthstone was in compliance with all covenants.
The Credit Facility is being terminated in connection with the exchange, and management expects it will be replaced with a new borrowing facility.
Overview of Capital Structure. Debt financing has been Earthstone’s sole source of external funding. In addition to routine production-related costs, general and administrative expenses and, when necessary, debt repayment requirements, Earthstone requires capital to fund its exploratory and development drilling efforts and the acquisition of additional properties as well as the enhancement of existing and newly acquired properties.
Hedging. During the three months ended June 30, 2014 and 2013, Earthstone did not participate in any hedging activities, nor did it have any open futures or option contracts.
Working Capital. As of June 30, 2014, Earthstone had working capital surplus of $1,548,000 (and a current ratio of 1.26:1), compared to a working capital surplus of $2,694,000 (and a current ratio of 1.47:1) as of March 31, 2014. The decrease in the current ratio is primarily a result of a decrease in other receivables and the repayment of $1,000,000 in debt out of Earthstone’s cash balance.
Cash Flow. Cash provided by operating activities was $2,644,000 for the three months ended June 30, 2014, compared to $2,888,000 for the three months ended June 30, 2013. Increases to cash provided by operating activities between the two comparable periods are primarily due to the fluctuation in deferred income tax expense and the increase in depletion primarily related to the increase in the oil and gas property balance. Decreases to cash provided by operating activities between the two comparable periods are primarily due to decreases in accounts receivable and the timing and payment of accounts payable, accrued and other liabilities, especially pertaining to capital expenditure outlays, in addition to the application of prepaid balances.
Overall, net cash used in investing activities decreased from $3,862,000 for the three months ended June 30, 2013 to $2,196,000 for the three months ended June 30, 2014. The decrease in cash used relates primarily to a decrease in the number of wells drilled and completed during the current period compared to the same period in the prior year, as explained below under “Capital Expenditures.”
Net cash used in financing activities was $1,000,000 for the three months ended June 30, 2014, compared to net cash provided by financing activities of $996,000 for the three months ended June 30, 2013. The decrease is related to repayments on the Credit Facility in the current period as compared to a borrowing for capital expenditures in the same period in the prior year, as further described below under “Capital Expenditures.”
The amounts presented herein are presented on an accrual basis, and as such may not be consistent with the amounts presented on the consolidated statements of cash flows under investing activities for expenditures on oil and gas property, which are presented on a cash basis.
During the three months ended June 30, 2014, Earthstone spent $2,578,000 on various projects. This compares to $4,640,000 for the three months ended June 30, 2013. During the three months ended June 30, 2014, capital expenditures were comprised of drilling and completions of wells producing as of period end (48%), drilling of 21 wells to be completed as of calendar year-end (50%), and acquiring leasehold acreage (2%). The majority (80%) of capital expenditures were spent in North Dakota. The remainder was spent in other areas on property improvements and leasehold acreage.
Earthstone is continually evaluating drilling and acquisition opportunities for possible participation. Typically, at any one time, several opportunities are in various stages of evaluation. Earthstone’s policy is to not disclose the specifics of a project or prospect, nor to speculate on such ventures, until such time as those various opportunities are finalized and undertaken.
Divestitures/Abandonments
Earthstone neither sold nor plugged any wells during the three months ended June 30, 2014.
Impact of Inflation and Pricing
Inflation has not had a material impact on Earthstone in recent years because of the relatively low rates of inflation in the United States. However, the oil and natural gas industry can be cyclical and the demand for production places pressure on the economic stability and pricing within the industry. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, cost declines are likely to lag and may not adjust downward in proportion to declining prices. Changes in prices impact revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect the ability to raise capital, borrow money, and retain personnel. While Earthstone does not presently expect business costs to materially rise, higher prices for oil and natural gas could result in increases in the costs of materials,
services and personnel.
Earthstone does not have any other commitments beyond its office lease.
Overview. Net income for the year ended March 31, 2014 was $3,939,000 compared to $1,780,000 for the year ended March 31, 2013, a 121% increase. Increases in sales volumes, coupled with increases in the sales price per barrel of oil equivalent (“BOE”), offset by higher production costs and DD&A expense, resulted in the increase in net income.
Revenues. Oil and natural gas sales revenue increased $6,458,000 (59%) from $10,982,000 for the year ended March 31, 2013 to $17,440,000 for the year ended March 31, 2014, due to an overall 9% higher realized price per BOE and a 46% overall increase in sales volumes.
Volumes and Prices. On an equivalent barrel basis, sales were 206,000 BOE for the year ended March 31, 2014 compared to 141,000 BOE for the year ended March 31, 2013, a 46% increase.
Oil sales volumes increased 42% from 122,655 barrels for the year ended March 31, 2013 to 173,880 barrels for the year ended March 31, 2014, while the average price per barrel increased 7% from $83.84 for the year ended March 31, 2013 to $89.91 for the year ended March 31, 2014. The rise in oil volumes resulted from production from newly producing wells offset, partially, by declines in existing wells.
Gas sales volumes increased 77% from 107,076 Mcf for the year ended March 31, 2013 to 189,933 Mcf for the year ended March 31, 2014, while the average price per Mcf increased 46%, from $6.53 for the year ended March 31, 2013 to $9.51 for the year ended March 31, 2014. The increase in volumes is primarily related to newly producing wells, coupled with a higher percentage of gas being sold from existing wells as midstream infrastructure is expanded, offset partially by declines in existing wells.
Production Expenses. Production expenses are comprised of the following items:
|
|
Year Ended
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$ |
2,920,000 |
|
|
$ |
2,563,000 |
|
Workover expenses
|
|
|
689,000 |
|
|
|
816,000 |
|
Transportation and other expenses
|
|
|
348,000 |
|
|
|
74,000 |
|
Total
|
|
$ |
3,957,000 |
|
|
$ |
3,453,000 |
|
Oil and gas production expense increased $504,000 (15%) for the year ended March 31, 2014, as compared to the year ended March 31, 2013. The two principal components of oil and gas production expense are routine lease operating expenses (“LOE”) and workovers. Routine expenses typically include such items as daily well maintenance, utilities, fuel, water disposal and minor surface equipment repairs. Workovers primarily include downhole repairs and are generally random in nature. Although workovers are expected, they can be much more frequent in some wells than others and their associated costs can be significant. Therefore, workovers account for more dramatic fluctuations in oil and gas production expense from period to period.
LOE and transportation and other expenses increased $357,000 (14%) and $274,000 (370%), respectively, for the year ended March 31, 2014, as compared to the year ended March 31, 2013. Workover expense decreased $127,000 (16%) from $816,000 for the year ended March 31, 2013 to $689,000 for the year ended March 31, 2014.
The overall lifting cost per BOE decreased $5.33 (22%) from $24.58 for the year ended March 31, 2013 to $19.25 for the year ended March 31, 2014. This decrease resulted from those costs being spread over larger reported BOE volumes. This lifting cost per equivalent barrel is not indicative of all wells, and certain high-cost wells could be shut-in should oil prices drop below certain levels.
Other Expenses. Depletion and depreciation expense increased $1,864,000 (92%) from $2,017,000 for the year ended March 31, 2013 to $3,881,000 for the year ended March 31, 2014 due to the addition of numerous high-cost North Dakota wells to the depletion base. These newer North Dakota wells reflect a higher investment per well than the remaining, un-expensed depletion base associated with Earthstone’s Legacy properties. Correspondingly, depletion expense per BOE increased from $13.89 for the year ended March 31, 2013 to $18.33 for the year ended March 31, 2014.
General and administrative (“G&A”) expense increased $3,000 (0.1%) from $2,625,000 for the year ended March 31, 2013 to $2,628,000 for the year ended March 31, 2014. This slight increase in costs is comprised primarily of increases in compensation-related expenses. As a percent of total sales revenue, G&A expense decreased from 23% for the year ended March 31, 2013 to 15% for the year ended March 31, 2014.
Income Tax. For the year ended March 31, 2014, Earthstone recorded income tax expense of $1,125,000. This amount consisted of a current period benefit of $390,000, resulting from the utilization of previously accumulated net operating losses, and deferred tax expense of $1,515,000. The effective income tax rate increased from 14.5% for the year ended March 31, 2013 to 22.2% for the year ended March 31, 2014. The effective income tax rate was higher for the year ended March 31, 2014 primarily due to a decrease in the percentage of current year excess depletion deduction between the comparable periods.
Overview. Net income for the three months ended June 30, 2014, was $997,000 compared to net income of $693,000 for the three months ended June 30, 2013. The increase in net income resulted from the increase in oil and gas production volumes and gas prices as described in “Revenues” and “Volumes and Prices” below.
Revenues. Oil sales revenue increased $993,000 (29%) for the three months ended June 30, 2014 to $4,373,000 from $3,380,000 for the three months ended June 30, 2013, due to the increase in oil sales volumes, offset by a lower realized price per barrel as described in “Volumes and Prices” below.
Gas sales revenue increased $639,000 (316%) for the three months ended June 30, 2014, compared to the three months ended June 30, 2013, as a result of the higher realized price per Mcf and an increase in gas sales volumes as described in “Volumes and Prices” below.
Volumes and Prices. Oil sales volumes increased by 32% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. In addition, the average price per barrel decreased by 2% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. The increase in oil sales volumes for the three months ended June 30, 2014, when compared to the three months ended June 30, 2013, was the result of an increase in production from newly producing wells, offset partially by declines in existing wells.
Gas sales volumes increased by 137% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. In addition, the average price per Mcf increased by 76% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. The increase in gas sales volumes for the three months ended June 30, 2014, when compared to the three months ended June 30, 2013, was the result of an overall increase in the percentage of natural gas production that was sold rather than being flared and the addition of gas sales from newly producing wells, which was offset partially by declines in existing
wells.
Production Expense. Production expense is comprised of the following items:
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|
Three Months Ended
|
|
|
|
|
|
|
|
|
Lease operating costs
|
|
$ |
700,000 |
|
|
$ |
697,000 |
|
Workover costs
|
|
|
150,000 |
|
|
|
116,000 |
|
Production taxes
|
|
|
473,000 |
|
|
|
309,000 |
|
Transportation and other costs
|
|
|
169,000 |
|
|
|
22,000 |
|
Total production expense
|
|
$ |
1,492,000 |
|
|
$ |
1,144,000 |
|
Oil and gas production expense increased $348,000 (30%) for the three months ended June 30, 2014, as compared to the expenses for the three months ended June 30, 2013, primarily due to an increase in production tax expense and transportation expense related to the increased production volume.
Routine LOE, consisting of field personnel, fuel/power, chemicals, disposal, transportation and other costs, per BOE was $14.51 for the three months ended June 30, 2014, compared to $17.25 for the three months ended June 30, 2013. While the total dollars spent on routine LOE was 21% higher between the comparable periods, the costs are being divided over more BOE in the three months ended June 30, 2014, resulting in a lower cost per BOE.
As a percent of oil and gas sales revenue, routine LOE was 17% for the three months ended June 30, 2014, compared to 20% for the three months ended June 30, 2013. This decrease in cost in proportion to revenue was due to a combination of the increase in gas prices, production volumes, and the number of producing wells between the comparable periods, coupled with a lower percentage increase in LOE costs between the comparable periods.
Workover operations, which generally consist of downhole repairs on a producing well, are conducted to restore or increase production and are generally random in nature. Therefore, workovers account for unpredictable fluctuations in oil and gas expense from period to period. The number of wells on which workover costs are expended varies as does the extent of workover operations. Workover expenses increased $34,000 (29%) for the three months ended June 30, 2014, compared to the respective period ended June 30, 2013. While total dollars spent on workovers increased between the comparable periods, the workover costs in the first quarter of fiscal 2015 decreased to $2.50 per BOE from $2.78 per BOE in the first quarter of fiscal 2014 due to being divided over more BOE in the current fiscal year.
Production taxes for the three months ended June 30, 2014 increased 53% over the three months ended June 30, 2013. As a percent of oil and gas sales revenue, production taxes remained the same between the two periods at 9%. Because production tax rates vary from state to state, Earthstone’s average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those jurisdictions.
While overall lifting costs (oil and gas production costs, including production taxes as well as workovers) increased during the three months ended June 30, 2014 in relation to the comparable period in the prior year, those costs are spread over larger reported volumes, per BOE, for the three months ended June 30, 2014, compared to the three months ended June 30, 2013, causing the costs per BOE to decrease from $27.45 to $24.91.
Other Expenses. Depletion and depreciation increased $359,000 (46%) for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. The increase in expense was a result of an increased dollar per barrel depletion rate and higher oil and gas sales. The higher dollar per barrel depletion rate was due to the addition of capital costs for newly drilled and/or completed wells into the pool of depletable property costs, which was partially offset by a decrease in the costs related to future development of proved undeveloped wells.
G&A expense increased $565,000 (82%) for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. The increase was primarily attributable to $627,000 of expenses related to the proposed transaction with Oak Valley, offset by a decrease in payroll, employee benefits and employee bonuses in the current fiscal year. The G&A expense increased during the three months ended June 30, 2014 in relation to the comparable period in the prior year, causing the costs per BOE to increase from $16.63 to $21.01.
Income Tax. For the three months ended June 30, 2014, Earthstone recorded income tax expense of $217,000, as compared to $168,000 for the three months ended June 30, 2013. Earthstone’s effective income tax rate was 17.9% for the three months ended June 30, 2014. The overall effective tax rate expressed as a percentage of book income before income tax for the three months ended June 30, 2014, as compared to the same period in 2013, was lower due primarily to an increase in the deduction for excess percentage depletion related to an increase in annualized oil and gas s
Recent Accounting Pronouncements
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). This ASU requires disclosure of both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. This guidance is required to be implemented for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on Earthstone’s consolidated financial statements.
In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for the fiscal quarter ending June 30, 2014. ASU 2013-11 impacts balance sheet presentation only. The impact of the new rule is not material.
Off-Balance Sheet Arrangements
Earthstone has no significant off-balance sheet transactions, arrangements or obligations.
Presently, Earthstone’s certificate of incorporation authorizes the issuance of 6,400,000 shares of common stock, $0.001 par value per share, and 600,000 shares of preferred stock, $0.001 par value per share. As of the record date, ___________ shares of common stock and no shares of preferred stock were issued and outstanding. Under applicable law, Earthstone is permitted to issue shares of its capital stock only to the extent such shares have been authorized for issuance under its certificate of incorporation. Consequently, under Earthstone’s present certificate of incorporation, Earthstone is permitted to issue only an additional ___________ shares, which is insufficient
to permit the issuance of the 9,124,452 shares to Oak Valley as provided in the exchange agreement. Consequently, it is a condition in the exchange agreement for the closing to occur that Earthstone’s certificate of incorporation be amended to increase the authorized shares of capital stock so that Earthstone can issue the required number of shares of common stock to complete the exchange.
Earthstone’s Board has approved, subject to stockholder approval, an amendment to Earthstone’s certificate of incorporation to increase the number of authorized shares of capital stock to 120,000,000 shares, consisting of 100,000,000 shares of common stock, par value $0.001 per share, and 20,000,000 shares of preferred stock, par value $0.001 per share. The amendment is attached as Annex D to this proxy statement.
The Earthstone Board believes this increase in the number of authorized shares of capital stock, beyond those needed to complete the exchange with Oak Valley, is desirable in order to provide Earthstone with adequate flexibility for this and future corporate planning and strategies. The availability of additional authorized shares of common stock and preferred stock could be used for a number of purposes, including corporate financing, public or private offerings of common or preferred stock, future acquisitions, stock dividends, stock splits, strategic relationships with corporate partners, stock options, and other stock-based compensation. The availability of additional authorized shares of capital stock is particularly important in the event that Earthstone’s Board needs to undertake any of the foregoing actions on an expedited basis, and avoids the time and expense of seeking stockholder approval in connection with the
contemplated issuance of common stock.
Other than the issuance of common stock in connection with the exchange, as set forth above, there are currently no plans, agreements or understandings regarding the issuance of any additional common stock or any preferred stock. Except for the dilution of the existing Earthstone stockholders’ ownership in the combined company after the exchange, the increase in authorized shares of common stock will not have any immediate effect on the rights of Earthstone stockholders, including voting rights, dividend rights, liquidation rights or any other stockholder rights. However, such additional authorized shares may be issued for such purposes and for such consideration as Earthstone’s Board may determine without further stockholder approval, including designating the rights, obligations and preferences of any issuance of preferred stock, unless stockholder approval is required by applicable law or NYSE MKT rules or the rules of
any stock exchange on which Earthstone’s securities may be listed.
The increase in authorized capital was not approved by the Board of Directors as a means of preventing or dissuading a change in control or takeover of Earthstone. However, use of these shares for such a purpose is possible. Authorized but unissued or unreserved shares of common stock, for example, could be issued in an effort to dilute the stock ownership and voting power of persons seeking to obtain control of Earthstone or could be issued to purchasers who would support the Board of Directors in opposing a takeover proposal. In addition, they may have the effect of discouraging a challenge for control or make it less likely that such a challenge, if attempted, would be successful. The Board of Directors and executive officers of Earthstone have no knowledge of any current effort to obtain control of Earthstone or to accumulate large amounts of common stock.
Earthstone’s obligation to complete the exchange agreement with Oak Valley is conditioned upon stockholder approval of the amendment of Earthstone’s certificate of incorporation; if the amendment is approved and the exchange is not completed for other reasons (including for lack of stockholder approval), the amendment will not be put into effect. The amendment to the Earthstone certificate of incorporation will be effected by way of the filing of the certificate of amendment with the Delaware Secretary of State following approval of the amendment by the Earthstone stockholders, in connection with or prior to the closing of the exchange and other related transactions.
No Exchange of Certificates
No exchange of stock certificates is necessary as a result of the amendment to increase the number of authorized shares of common stock.
The affirmative vote of the holders of a majority of the shares of Earthstone’s common stock outstanding as of the record date is required for approval of the amendment to the certificate of incorporation under the Delaware General Corporation Law.
THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS
THAT THE EARTHSTONE STOCKHOLDERS VOTE “FOR” THE PROPOSED AMENDMENT TO THE CERTIFICATE
OF INCORPORATION INCREASING THE AUTHORIZED CAPITAL STOCK OF EARTHSTONE.
PROPOSAL 3 – APPROVAL AND ADOPTION OF THE EARTHSTONE 2014 LONG-TERM INCENTIVE PLAN
Reasons for and Explanation of Proposal
At the special meeting, the stockholders will be asked to approve and adopt the Earthstone Energy, Inc. 2014 Long-Term Incentive Plan, which is referred to as the 2014 Plan.
Summary of Principal Terms of the 2014 Plan
The following is a summary description of the material features of the 2014 Plan. The statements made in this proxy statement regarding the 2014 Plan should be read in conjunction with and are qualified in their entirety by reference to the 2014 Plan, a copy of which is attached as Annex E to this proxy statement.
The 2014 Plan, if approved, will be effective upon the closing of the transactions contemplated by the exchange agreement and shall remain in effect until the day prior to the tenth anniversary thereof. The purposes of the 2014 Plan are to create incentives which are designed to motivate participants to put forth maximum effort toward Earthstone’s success and growth and to enable it to attract and retain experienced individuals who, by their position, ability and diligence are able to make important contributions to Earthstone’s success.
Under the 2014 Plan, Earthstone may grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards to Earthstone’s employees or those of its subsidiaries or affiliates. Earthstone may also grant nonqualified stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2014 Plan. Generally, all classes of Earthstone’s employees are eligible to participate in the 2014 Plan. As of September 15, 2014, there were approximately 49 full-time employees, two part-time employees, seven
contractors, and five non-employee directors of the combined company that would be eligible to participate in the 2014 Plan if it were to become effective.
The 2014 Plan currently provides that a maximum of 750,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. Please see the section entitled “Recent Share Prices” above for information concerning the market value of the common stock. As of March 31, 2014, there were approximately 138,959 shares of common stock available for awards to be granted under the Earthstone 2011 Equity Incentive Compensation Plan. If the 2014 Plan is approved and adopted by Earthstone’s stockholders, and the exchange with Oak Valley is consummated, no further awards will be made under the 2011 Equity Incentive Compensation Plan. If the 2014 Plan is approved and adopted as proposed herein, approximately 750,000 shares of common stock would be available for new awards to be granted under the 2014 Plan. However, because the 2014 Plan is newly adopted and
all awards to be made thereunder are discretionary, the benefits or amounts to be received by eligible participants cannot be determined at this time. Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued. Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan.
The 2014 Plan, as proposed, limits the aggregate number of shares of common stock that may be covered by stock options and/or stock appreciation rights granted to any eligible employee in any calendar year to 250,000 shares. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with awards (other than stock options or stock appreciation rights) granted to any eligible employee in any calendar year to 150,000 shares. The 2014 Plan also limits the maximum aggregate amount that may be paid in cash pursuant to awards (other than stock options or stock appreciation rights) made to any eligible employee in any calendar year to $2,000,000.
The board of directors or a committee appointed by the board of directors will administer the 2014 Plan. Except as set forth in the 2014 Plan, the committee will serve at the pleasure of the board of directors.
Awards to directors under the 2014 Plan must be approved by the board of directors.
In connection with the administration of the 2014 Plan, the board of directors or the committee, with respect to awards to be made to any officer, employee or consultant who is not one of Earthstone’s directors, will:
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determine which employees and other persons will be granted awards under the 2014 Plan;
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grant the awards to those selected to participate;
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determine the exercise price for options and stock appreciation rights; and
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prescribe any limitations, restrictions and conditions upon any awards.
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In addition, the board of directors or the committee will:
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interpret the 2014 Plan; and
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make all other determinations and take all other actions that may be necessary or advisable to implement and administer the 2014 Plan.
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Types of Awards
The 2014 Plan permits the board of directors or the committee to make several types of awards and grants, including awards of shares of restricted stock, awards of restricted stock units, the grant of options to purchase shares of common stock, awards of stock appreciation rights (SARs), awards of performance units, awards of performance bonuses, stock awards and other incentive awards.
Restricted Stock. Restricted shares of common stock may be granted under the 2014 Plan subject to such terms and conditions, including forfeiture and vesting provisions, and restrictions against sale, transfer or other disposition as the board of directors or committee may determine to be appropriate at the time of making the award. In addition to any time vesting conditions determined by the board of directors or committee, vesting and/or the grant of restricted stock awards may be subject to Earthstone’s achievement of specified performance criteria. In addition, the board of directors or committee may direct that share certificates representing restricted stock be inscribed with a legend as to the restrictions on sale, transfer or other disposition, and may direct that the certificates, along with a stock power signed in blank by the employee, be delivered to and held by Earthstone
until such restrictions lapse. Shares of restricted stock will generally vest upon the occurrence of a change of control. The board of directors or committee, in its discretion, may provide for an acceleration of vesting of restricted stock in the event of death or permanent disability of the employee, or for such other reasons as the board of directors or committee may deem appropriate in the event of the termination of a participant.
Restricted Stock Units. A restricted stock unit entitles the recipient to receive a payment from Earthstone, following the lapse of restrictions on the award, equal to the fair market value of a share of common stock. The 2014 Plan provides for payment in the form of shares of common stock or cash. Restricted stock units may be granted under the 2014 Plan subject to such terms and conditions, including forfeiture and vesting provisions as the board of directors or committee may determine to be appropriate at the time of making the award. In addition to any time vesting conditions determined by the board of directors or committee, vesting and/or the grant of restricted stock units may be subject to Earthstone’s achievement of specified performance criteria. Restricted stock units would generally vest upon the occurrence of a change of control. The board of directors or committee, in its discretion, may
provide for an acceleration of vesting of restricted stock units in the event of death or permanent disability of the employee, or for such other reasons as the board of directors or committee may deem appropriate in the event of the termination of a participant.
The 2014 Plan also permits the board of directors or committee to grant tandem cash dividend rights or dividend unit rights with respect to restricted stock units. A cash dividend right is a contingent right to receive an amount in cash equal to the cash distributions made by Earthstone with respect to a share of common stock during the period the tandem restricted stock unit is outstanding. A grant of cash dividend rights may provide that such cash payments shall be paid directly to the participant at the time of payment of the related dividend, be credited to a bookkeeping account subject to the same vesting and payment provisions as the tandem restricted stock unit award (with or without interest in the discretion of the board of directors or committee), or be subject to such other provisions or restrictions as determined in the discretion of the board of directors or committee. A dividend unit right is a contingent right
to have an additional number of restricted stock units credited to a participant in respect of a restricted stock unit award equal to the number of shares of common stock that could be purchased at fair market value upon, and with the amount of, each cash distribution made by Earthstone with respect to a share of common stock during the period the tandem restricted stock unit is outstanding. A grant of dividend unit rights may provide that such dividend unit rights shall be subject to the same vesting and payment provisions as the tandem restricted stock unit award or be subject to such other provisions and restrictions as determined in the discretion of the board of directors or committee.
Stock Options. Stock options are contractual rights entitling an optionee who has been granted a stock option to purchase a stated number of shares of common stock at an exercise price per share determined at the date of the grant. Options are evidenced by stock option agreements with the respective optionees. The exercise price for each stock option granted under the 2014 Plan will be determined by the board of directors or committee at the time of the grant. Either the board of directors or committee will also determine the duration of each option; however, no option may be exercisable more than ten years after the date the option is granted. Within the foregoing limitations, either the board of directors or committee may, in its discretion, impose limitations on the exercise of all or some options granted under the 2014 Plan, such as specifying minimum periods of time after grant during which options
may not be exercised. The 2014 Plan generally provides for acceleration of the right of an individual employee to exercise his or her stock option in the event Earthstone experiences a change of control.
The 2014 Plan provides that the stock options may either be incentive stock options within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended (the “Code”), or nonqualified options, which are stock options other than incentive stock options.
Incentive Stock Options. Incentive stock options may be granted only to Earthstone’s employees or employees of Earthstone’s subsidiaries, and must be granted at a per share exercise price not less than the fair market value of common stock on the date the incentive stock option is granted. In the case of an incentive stock option granted to a stockholder who owns shares of Earthstone’s outstanding stock of all classes representing more than 10% of the total combined voting power of all of Earthstone’s outstanding stock of all classes entitled to vote in the election of directors, the per share exercise price may not be less than 110% of the fair market value of common stock on the date the incentive stock option is granted and the term of such option may not exceed five years. As required by the Code, the aggregate
fair market value, determined at the time an incentive stock option is granted, of common stock with respect to which incentive stock options may be exercised by an optionee for the first time during any calendar year under all of Earthstone’s incentive stock option plans may not exceed $100,000.
Nonqualified Options. Nonqualified options are stock options which do not qualify as incentive stock options under the Code. Nonqualified options may be granted to directors and consultants, as well as to employees, or those directors, consultants, and employees of subsidiaries in which Earthstone has a controlling interest. The exercise price for nonqualified options will be determined by the board of directors or the committee at the time the nonqualified options are granted, but may not be less than the fair market value of Earthstone’s common stock on the date the nonqualified option is granted. Nonqualified options are not subject to any of the restrictions described above with respect to incentive stock options. Incentive stock options and nonqualified options are treated differently for federal income tax
purposes as described below under “– Tax Treatment.”
The 2014 Plan provides that the exercise price of stock options may be paid (1) in cash, (2) subject to the prior approval by the board of directors or committee, in whole shares of common stock, (3) subject to the prior approval by the board of directors or committee, by withholding shares of common stock which otherwise would be acquired on exercise, or (4) subject to the prior approval by the board of directors or committee, by a combination of the foregoing, equal in value to the exercise price. The board of directors or committee may also permit a stock option to be exercised by a broker-dealer acting on behalf of a participant through procedures approved by the board of directors or committee, as applicable.
Stock Appreciation Rights. Awards of stock appreciation rights, which Earthstone refers to as SARs, entitle the recipient to receive a payment from Earthstone equal to the amount of any increase in the fair market value of the shares of common stock subject to the SAR award between the date of the grant of the SAR award and the exercise date. The 2014 Plan provides for payment in the form of shares of common stock or cash. The 2014 Plan generally provides for acceleration of the right of an individual employee to exercise his or her SAR in the event Earthstone experiences a change of control.
Performance Unit Awards. Performance units entitle the recipient to receive a certain target, maximum or minimum value in cash or common stock per unit upon the achievement of performance goals established by the board of directors or committee.
Performance Bonuses. A performance bonus entitles the recipient to receive a cash bonus upon the attainment of a performance target established by the board of directors or committee. The 2014 Plan permits payment of performance bonuses in the form of cash or common stock.
Stock Awards. A stock award entitles the recipient to shares of common stock not subject to vesting or forfeiture restrictions. Stock awards are awarded with respect to such number of shares of common stock and at such times as the board of directors or committee may determine, and the board of directors or committee may require a participant to pay a stipulated purchase price for each share of common stock covered by a stock award.
Other Incentive Awards. The 2014 Plan permits the grant of other incentive awards based upon, payable in or otherwise related to, in whole or in part, shares of common stock if the board of directors or committee determines that such other incentive awards are consistent with the purposes of the 2014 Plan. Such other incentive awards may include, but are not limited to, common stock awarded as a bonus, dividend equivalents, convertible or exchangeable debt securities, other rights convertible or exchangeable into common stock, purchase rights for common stock, awards with value and payment contingent upon Earthstone’s performance or any other factors designated by the board of directors or committee, and awards valued by reference to the book value of common stock or the value of securities or the performance of specified subsidiaries.
Long-term cash awards are also permitted under the 2014 Plan. Cash awards are also permitted as an element of or a supplement to any awards permitted under the 2014 Plan. Awards are permitted in lieu of obligations to pay cash or deliver other property under the 2014 Plan or under other plans or compensation arrangements, subject to any applicable provision under Section 16 of the Exchange Act.
The 2014 Plan provides the board of directors or compensation committee discretion to determine whether all or any portion of a restricted stock award, restricted stock unit award, performance unit award, performance bonus, stock award or other incentive award is intended to satisfy the requirements for “performance-based compensation” under Section 162(m) of the Code (the “162(m) Requirements”). The performance criteria for any such award that is intended to satisfy the 162(m) Requirements would be established in writing by a committee composed of two or more “outside directors” within the meaning of Section 162(m) of the Code based on one or more performance criteria listed above not later than 90 days after commencement of the performance period with respect to such award or any such other date as may be required or permitted for “performance-based compensation” under the 162(m) Requirements;
provided that the outcome of the performance in respect of the goals remains substantially uncertain as of such time. At the time of the grant of an award and to the extent permitted under the 162(m) Requirements, the committee may provide for the manner in which the performance goals would be measured in light of specified corporate transactions, extraordinary events, accounting changes or other similar occurrences. All determinations made by the committee as to the establishment or the achievement of performance goals, or the final settlement of an award intended to satisfy the 162(m) Requirements would be required to be made in writing. The committee would have discretion to reduce, but not to increase, the amount payable and/or the number of shares of common stock to be granted, issued, retained or vested pursuant to any such award.
The performance criteria to be used for purposes of awards under the 2014 Plan that are intended to meet the 162(m) Requirements are set in the sole discretion of the board of directors or compensation committee and may be described in terms of objectives that are related to the individual participant or objectives that are company-wide or related to a subsidiary, division, department, region, function or business unit of Earthstone in which the participant is employed or with respect to which the participant performs services, and shall consist of one or more or any combination of the following criteria: operational criteria, including reserve additions/replacements, finding and development costs, production volume and production costs; financial criteria, including earnings (net income, earnings before interest, taxes, depreciation and amortization (“EBITDA”), earnings per share), free cash flow, cash flow, operating
income, general and administrative expenses, ratios of debt to equity, debt to cash flow, debt to EBITDA, and EBITDA to interest, return on assets, return on equity, return on invested capital, and profit returns/margins; and stock performance criteria, including stock price appreciation, total stockholder return and relative stock price performance.
Nonqualified options are transferable on a limited basis. Other types of awards authorized under the 2014 Plan are not transferable other than by will or by the laws of descent and distribution. In no event may a stock option be exercised after the expiration of its stated term.
Rights to restricted stock, restricted stock units, SARs, performance units, performance bonuses and other incentive awards which have not vested will generally terminate immediately upon the holder’s termination of employment with Earthstone or any of its subsidiaries or affiliates for any reason other than disability or death. Unless the board of directors or committee specifies otherwise in an award agreement, if an employee’s employment with Earthstone or any of its subsidiaries or affiliates terminates as a result of death, disability or retirement, the employee (or personal representative in the case of death) may exercise any vested incentive stock options for a period of up to three months after such termination (one year in the case of death
or disability in lieu of the three-month period) and any vested nonqualified option during the remaining term of the option. Unless the board of directors or committee specifies otherwise in an award agreement, if an employee’s employment with Earthstone or any of its subsidiaries or affiliates terminates for any other reason, the employee may exercise any vested option for a period of up to three months after such termination. Unless the board of directors or committee specifies otherwise in an award agreement, if a consultant ceases to provide services to Earthstone or any of its subsidiaries or affiliates or a director terminates service as a director, the unvested portion of any award will be forfeited unless otherwise accelerated by the board of directors or committee. Unless the board
of directors or committee specifies otherwise in an award agreement, a consultant or director may have three years following the date he or she ceases to provide consulting services or ceases to be a director, as applicable, to exercise any nonqualified options which are otherwise exercisable on the date of termination of service. No stock option or SAR may be exercised following the expiration date of the stock option or SAR.
The 2014 Plan provides protection against substantial dilution or enlargement of the rights granted to holders of awards in the event of stock splits, recapitalizations, mergers, consolidations, reorganizations or similar transactions. The 2014 Plan provides that, upon the occurrence of a change of control event, the board of directors or committee would have discretion, without the consent of any participant or holder of an award, to the extent permitted by applicable law, to cancel awards and make payments in respect thereof in cash; replace awards with other rights or property selected by the board of directors or committee; provide that awards will be assumed by a successor or survivor entity (or a parent or subsidiary thereof) or be exchanged for similar rights or awards based on the equity of the successor or survivor (or a parent or subsidiary thereof); adjust outstanding awards as appropriate to reflect the change
of control event; accelerate any vesting schedule to which an award is subject; provide that awards are payable; and/or provide that awards terminate upon such event.
The board of directors may amend the 2014 Plan at any time. However, without stockholder approval, the 2014 Plan may not be amended in a manner that would increase the number of shares that may be issued under the 2014 Plan, materially modify the requirements as to eligibility for participation in the 2014 Plan, or materially increase the benefits to participants provided by the 2014 Plan.
The following is a brief description of the federal income tax consequences, under existing law, with respect to awards that may be granted under the 2014 Plan. This summary is not intended to provide or supplement tax advice to eligible employees. This summary is not intended to be exhaustive and does not describe state, local or foreign consequences, employment tax consequences, or the effect, if any, of gift, estate and inheritance taxes.
Restricted Stock. A recipient of restricted stock generally will not recognize taxable income until the shares of restricted stock become freely transferable or are no longer subject to a substantial risk of forfeiture. At that time, the excess of the fair market value of the restricted stock over the amount, if any, paid for the restricted stock is taxable to the recipient as ordinary income. If a recipient of restricted stock subsequently sells the shares, he or she generally will realize capital gain or loss (long-term or short-term depending on the holding period) in the year of such sale in an amount equal to the difference between the amount realized from the sale and his or her basis in the stock, which is equal to the price paid for the stock, if any.
A recipient has the opportunity, within certain limits, to fix the amount and timing of the ordinary income attributable to a grant of restricted stock. Section 83(b) of the Code permits a recipient of restricted stock, which is not yet required to be included in taxable income, to elect, within 30 days of the award of restricted stock, to include in ordinary income immediately the difference between the fair market value of the shares of restricted stock at the date of the award and the amount paid for the restricted stock, if any. The election permits the recipient of restricted stock to fix the amount of income that must be recognized by virtue of the restricted stock grant. Subject to Section 162(m) of the Code, Earthstone generally will be entitled to a deduction in the year the recipient is required (or elects) to recognize income by virtue of receipt of restricted stock, equal to the amount of taxable
income recognized by the recipient.
Restricted Stock Units. A recipient of restricted stock units generally will not recognize taxable income until the recipient receives cash and/or the transfer of shares in satisfaction of the restricted stock unit award. At that time, an amount equal to the aggregate of any cash and the fair market value of any shares received is taxable to the recipient as ordinary income. If a recipient of restricted stock units subsequently sells any shares so transferred, he or she generally will realize capital gain or loss (long-term or short-term depending on the holding period) in the year of such sale in an amount equal to the difference between the amount realized from the sale and his or her basis in the stock, which is equal to the amount previously included in income as ordinary income with respect to such shares.
Subject to Section 162(m) of the Code, Earthstone generally will be entitled to a deduction in the year the recipient is required to recognize income by virtue of receipt of cash or shares, equal to the amount of taxable income recognized by the recipient.
Incentive Stock Options. An optionee will not realize taxable income upon the grant of an incentive stock option. As long as the optionee has been an employee of Earthstone or of one of its permissible corporate subsidiaries from the date of grant through the date the incentive stock option is exercised and if the incentive stock option is exercised during his or her period of employment and within three months after termination, the optionee will not recognize taxable income upon exercise. Upon exercise, however, the amount by which the fair market value of the shares with respect to which the incentive stock option is exercised (determined on the date of exercise) exceeds the exercise price paid will be an item of tax preference to which the alternative minimum tax may apply, depending on each optionee’s individual
circumstances. If the optionee does not dispose of the shares of common stock acquired by exercising an incentive stock option within two years from the date of the grant of the incentive stock option or within one year after the shares are transferred to the optionee, when the optionee later sells or otherwise disposes of the stock, any amount realized by the optionee in excess of the exercise price will be taxed as a long-term capital gain and any loss will be recognized as a long-term capital loss. Earthstone generally will not be entitled to an income tax deduction with respect to the grant or exercise of an incentive stock option.
If any shares of common stock acquired upon exercise of an incentive stock option are resold or disposed of before the expiration of the prescribed holding periods, the optionee will realize ordinary compensation income (and perhaps some short-term capital gain as well) instead of long-term capital gain. The amount of the ordinary compensation income realized will generally be equal to the lesser of (i) the excess of the fair market value of the stock on the exercise date over the exercise price; or (ii) the excess of the amount realized upon the sale over the exercise price. Any additional gain would generally be short-term capital gain.
In the event of a premature disposition of shares of stock acquired by exercising an incentive stock option, subject to Section 162(m) of the Code, Earthstone generally would be entitled to a deduction equal to the amount of ordinary compensation income realized by the optionee.
If an optionee uses already owned shares of common stock to pay the exercise price under an incentive stock option, the resulting tax consequences will depend upon whether the already owned shares of common stock are “statutory option stock,” and, if so, whether the statutory option stock has been held by the optionee for the applicable holding period referred to in Section 424(c)(3)(A) of the Code. In general, “statutory option stock” is any stock acquired through the exercise of an incentive stock option or an option granted pursuant to an employee stock purchase plan, but not stock acquired through the exercise of a nonqualified stock option. If the stock is statutory option stock with respect to which the applicable holding period has been satisfied, or if the stock is not statutory option stock, no income will be recognized by the optionee upon the transfer of the stock in payment of the exercise price of
an incentive stock option. If the stock used to pay the exercise price is statutory option stock with respect to which the applicable holding period has not been satisfied, the transfer of the stock will be a premature disposition, as described above, which will result in the recognition of ordinary income by the optionee in an amount equal to the excess of the fair market value of the statutory option stock at the time the incentive stock option covering the stock was exercised over the amount paid for the stock.
If an optionee effects a net exercise of an incentive stock option by surrendering a portion of the shares of stock with respect to which the option is exercisable to pay the exercise price, the surrender of the stock will result in the recognition of ordinary income by the optionee in an amount equal to the fair market value of the surrendered stock.
Nonqualified Options. An optionee will not realize taxable income upon the grant of a nonqualified option. At the time the optionee exercises the nonqualified option, the amount by which the fair market value, at the time of exercise, of the shares with respect to which the nonqualified option is exercised exceeds the exercise price paid upon exercise will constitute ordinary income to the optionee in the year of such exercise. Subject to Section 162(m) of the Code, Earthstone generally will be entitled to a corresponding income tax deduction in the year of exercise equal to the ordinary income recognized by the optionee. If the optionee thereafter sells such shares, the difference between any amount realized on the sale and the fair market value of the shares at the time of exercise will be taxed to the optionee as a capital gain or loss, short-term or long-term depending on the length of time the stock
was held by the optionee before sale.
If an optionee uses already owned shares of common stock to pay the exercise price under a nonqualified option, the number of shares received pursuant to the nonqualified option which is equal to the number of shares delivered in payment of the exercise price will be considered received in a nontaxable exchange, and the fair market value of the remaining shares received by the optionee upon the exercise will be taxable to the optionee as ordinary income.
Stock Appreciation Rights. A recipient of SARs will not realize taxable income upon the grant of a SAR. At the time the recipient exercises the SAR, an amount equal to the aggregate of any cash and the fair market value of any shares received is taxable to the recipient as ordinary income in the year of such exercise. Subject to Section 162(m) of the Code, Earthstone generally will be entitled to a corresponding income tax deduction in the year of exercise equal to the ordinary income recognized by the recipient. If the recipient thereafter sells any shares received upon exercise, the difference between any amount realized on the sale and the fair market value of the shares at the time of exercise will be taxed to the recipient as a capital gain or loss, short-term or long-term depending on the length of time the stock was held by the recipient before sale.
Performance Units and Performance Bonuses. A recipient of performance units or a performance bonus generally will not realize taxable income upon the grant of such award. The recipient will recognize ordinary income upon the receipt of cash and/or the transfer of shares in satisfaction of the award of performance units or performance bonus in an amount equal to the aggregate of any cash and the fair market value of any shares received. If an award is “performance-based compensation” under Section 162(m) of the Code, Earthstone generally will be entitled to a corresponding income tax deduction in the year of exercise equal to the ordinary income recognized by the recipient. Otherwise, Earthstone’s deduction may be limited by Section 162(m) of the Code as described below. If the recipient thereafter sells any shares received in satisfaction of the award, the difference between any amount realized
on the sale and the fair market value of the shares at the time of their receipt will be taxed to the recipient as a capital gain or loss, short-term or long-term depending on the length of time the stock was held by the recipient before sale.
Stock Awards. A recipient of a stock award will recognize ordinary income upon the receipt of shares in an amount equal to the fair market value of any shares received over the amount, if any, paid for the shares. Subject to Section 162(m) of the Code, Earthstone generally will be entitled to a corresponding income tax deduction equal to the ordinary income recognized by the recipient. If a recipient subsequently sells the shares, he or she generally will realize capital gain or loss (long-term or short-term depending on the holding period) in the year of such sale in an amount equal to the difference between the net proceeds from the sale and the participant’s basis in the stock, which is generally equal to the fair market value of the stock on the date of receipt.
Other Incentive Awards. The specific tax consequences applicable with respect to other incentive awards granted under the 2014 Plan will depend on the terms and conditions applicable to the award.
Code Section 162(m). Section 162(m) of the Code places a $1 million cap on the deductible compensation that may be paid to certain executives of publicly traded corporations. Amounts that qualify as “performance-based compensation” under Section 162(m) of the Code are exempt from the cap and do not count toward the $1 million limit. In order to be “performance-based compensation” exempt from the $1 million deductibility limitation, the grant or vesting of the award relating to the compensation must (among other things) be based on the satisfaction of one or more performance goals specified a compensation committee made up of at least two “outside directors.” Generally, stock options and stock appreciation rights are intended to qualify as performance-based compensation. Other awards may or may not so qualify, depending on their terms. In any event, Earthstone reserves the right to
award compensation that is not “performance-based compensation” and that is not deductible under Section 162(m) of the Code, and in no event shall Earthstone or any member of the board or the compensation committee be liable in the event that any award fails to qualify as “performance-based compensation” under Section 162(m) of the Code.
To ensure compliance with Treasury Department Circular 230, participants are hereby notified that (i) any discussion of U.S. federal tax issues in this proxy statement is not intended to be written or used, and cannot be used, for the purpose of avoiding penalties that may be imposed under the Code, and (ii) participants should seek advice based on their particular circumstances from an independent tax advisor.
Current Plan and Outstanding Options
The following table provides information as March 31, 2014, regarding compensation plans (including individual compensation arrangements) under which equity securities of Earthstone are authorized for issuance. The table includes information regarding both the 2011 Equity Incentive Compensation Plan and the Director Compensation Plan.
Equity Compensation Plan Information
Plan Category
|
|
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
|
|
|
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights
|
|
|
Number of Securities Remaining Available for Future Issuance
|
|
Equity compensation plans approved by security holders:
|
|
|
|
|
|
|
|
|
|
2011 Equity Incentive Compensation Plan
|
|
|
6,849 |
|
|
$ |
20.28 |
(1) |
|
|
138,959 |
|
Director Compensation Plan
|
|
|
11,726 |
|
|
$ |
18.42 |
(1) |
|
|
3,661 |
|
(1)
|
Weighted average grant prices have been developed utilizing the number of unvested shares relative to the date of grant values for the respective tranches of shares issued under the 2011 Equity Incentive Compensation Plan and the Director Compensation Plan.
|
Approval of the proposal to approve and adopt the 2014 Plan requires the affirmative vote of a majority of the shares of common stock represented in person or by proxy at the special meeting and voting on such proposal, provided that such shares voting affirmatively must also constitute a majority of the required quorum for the meeting.
Because approval by the Earthstone stockholders of the 2014 Plan is a condition to closing under the exchange agreement, unless this condition is waived by the parties to the exchange agreement, failure to approve and adopt the 2014 Plan will cause the exchange agreement to be terminated, and the exchange and other transactions contemplated therein will not take place. If the transactions pursuant to the exchange agreement are not consummated for any reason, including a lack of the requisite vote of stockholders of Earthstone, and the proposal to approve and adopt the 2014 Plan receives Earthstone stockholder approval, the 2014 Plan will not become effective.
The board of directors believes that approval and adoption of the proposed 2014 Plan will promote Earthstone’s interests and the interests of the stockholders and continue to enable Earthstone to attract, retain and reward persons important to Earthstone’s success and to provide incentives based on the attainment of corporate objectives and increases in shareholder value. Members of the board of directors are eligible to participate in the 2014 Plan, and thus, have a personal interest in the approval and adoption of the 2014 Plan.
THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS THAT THE EARTHSTONE STOCKHOLDERS
VOTE “FOR” THE APPROVAL AND ADOPTION OF THE 2014 PLAN.
PROPOSAL 4 – ADVISORY VOTE REGARDING EMPLOYEE SEVERANCE COMPENSATION PLAN
The Non-Binding Advisory Proposal
Section 14A of the Exchange Act, which was enacted as part of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, requires companies to provide their stockholders with the opportunity to vote to approve, on a non-binding advisory basis, certain compensation arrangements for its named executive officers, including compensation arrangements entered into that are based on or otherwise related to an acquisition, merger or disposition transaction. Therefore, Earthstone is asking its stockholders to approve the severance compensation arrangements and payments which certain named executive officers may be eligible to receive in connection with the exchange. The Severance Plan was previously disclosed to Earthstone stockholders in the company’s Current Report on Form 8-K filed with the SEC on May 16,
2014. The Severance Plan is attached as Annex F to this proxy statement. The description of the Severance Plan below is a summary, and is qualified in its entirety by the full terms of the Severance Plan. The Severance Plan was adopted and approved by the Earthstone Board on May 13, 2014, and is believed to be reasonable and in line with marketplace norms. Accordingly, the board of directors of Earthstone unanimously recommends that the company’s stockholders approve the following resolution at the special meeting:
“RESOLVED, that the stockholders of Earthstone Energy, Inc. approve, solely on a non-binding advisory basis, the compensation which may be paid to certain named executive officers of Earthstone Energy, Inc. in connection with the exchange and pursuant to the Employee Severance Compensation Plan.”
Potential Payments upon Termination or Change of Control/Golden Parachute Compensation
The Severance Plan will provide benefits to participating employees designated by the Board upon a qualifying termination of employment. All of Earthstone’s Denver-based employees have been named participants in the Severance Plan, including Earthstone’s Chief Executive Officer, Ray Singleton. Earthstone’s only other executive officer, who is working for Earthstone pursuant to a consulting arrangement, has not been named a participant in the Severance Plan. The Board believes that the Severance Plan is important in Earthstone’s ability to retain employees through the completion of the exchange whose efforts will be significant in completing the exchange.
Under the Severance Plan, participants are entitled to receive certain severance benefits if the following conditions are met: (A) the exchange or a similar change of control transaction is consummated, and (B) the employee’s employment is terminated by Earthstone other than for “cause” or due to the participant’s “disability,” or by the employee for “good reason,” within one year following such change of control transaction. The severance benefits include (i) a cash severance payment, the amount of which is equal to the weekly base salary times a number derived from the employee’s period of service, with a minimum of 17 weeks and maximum of 52 weeks, and (ii) up to nine months of premiums for continuation coverage under COBRA. Specifically, the cash severance payment is equal to (i) the employee’s weekly base salary times 17 plus (ii) the product of (A) three times (B) the number of years of service with
Earthstone. In addition, the Severance Plan provides that all unvested restricted stock held by designated employees vests upon a change of control.
In the case of Mr. Singleton, the exchange agreement contemplates that he would remain employed by Earthstone following the closing in the capacity of “Executive Vice President – Northern Region.” If (A) the exchange or similar change of control transaction is consummated, and (B) Mr. Singleton is terminated by Earthstone from his new position other than for “cause” or disability, or if he terminates his employment for “good reason,” in each case, within one year following closing, he would be entitled to receive the severance benefits provided in the Severance Plan. The amount payable to Mr. Singleton would be equal to one year of his base salary, which is currently $231,000, plus the payment of COBRA premiums as described above. If the exchange or a similar change of control transaction is not consummated, or if the exchange occurs but Mr. Singleton is not terminated under the circumstances
described above within one year following closing, he will not be entitled to receive any payment under the Severance Plan.
In addition, the Severance Plan includes a perpetual confidentiality covenant and provisions requiring Earthstone to indemnify the participant for attorneys’ fees and costs in the event the participant brings a legal proceeding to enforce the participant’s rights under the Severance Plan.
“Change of control” is defined in the Severance Plan as the occurrence of any of the following:
●
|
any individual, entity, or group has acquired beneficial ownership of 50% or more of the combined voting power of Earthstone;
|
●
|
individuals making up the incumbent Board cease for any reason to constitute at least a majority of the Board;
|
●
|
Earthstone consummates a merger or consolidation in which persons who were the stockholders of Earthstone immediately prior to such transaction do not, immediately thereafter, own more than 50% of the then-outstanding shares of the merged or consolidated company after the merger; or
|
●
|
a liquidation or dissolution of Earthstone or the sale of all or substantially all of the assets of Earthstone.
|
“Cause” is defined in the Severance Plan as (i) conviction of a felony or a crime involving fraud or moral turpitude; (ii) theft, a material act of dishonesty or fraud, intentional falsification of any employment or company records, or commission of any criminal act which impairs the employee’s ability to perform appropriate employment duties for Earthstone; (iii) intentional or reckless conduct or gross negligence materially harmful to Earthstone or any successor thereto, including violation of a non-competition or confidentiality agreement, if any; or (iv) gross negligence or willful misconduct in the performance of the employee’s assigned duties. Cause shall not include mere unsatisfactory performance in the achievement of the employee’s job objectives.
Under the Severance Plan, “good reason” means any of the following events or conditions which occur without the participant’s written consent, and which remain in effect after notice has been provided by the participant to Earthstone of such event and the expiration of a 30-day cure period:
●
|
a material reduction in the participant’s base salary compensation;
|
●
|
a material diminution in the participant’s authority, duties or responsibilities; or
|
●
|
a material change in the geographic location at which the participant performs services.
|
Other than the Severance Plan adopted in conjunction with the exchange agreement, Earthstone has no contract with any officer that would give rise to any cash or non-cash compensation resulting from the resignation, retirement or any other termination of such officer’s employment with Earthstone or from a change of control of Earthstone or a change in any officer’s responsibilities following a change of control. Currently, all executive officers serve at the pleasure of the Board.
The following table sets forth the estimated payments due to named executive officers under the Severance Plan. The table assumes that (i) the exchange occurred on September 15, 2014, (ii) the Severance Plan was in effect at the assumed date of the exchange, and (iii) Mr. Singleton was terminated at the assumed date of the exchange.
Golden Parachute Compensation
|
|
|
|
|
|
|
|
|
|
Perquisites/
Benefits ($)
|
|
|
|
|
President and Chief Executive Officer
|
|
$ |
231,000 |
(a) |
|
$ |
54,921 |
(b) |
|
$ |
15,830 |
(c) |
|
$ |
301,775 |
|
(a)
|
Cash compensation equals (i) weekly base salary times seventeen (17) plus (ii) the product of (A) three (3), times (B) the number of years of service with Earthstone, subject to a fifty-two (52) week maximum. The amount payable to Mr. Singleton would be equal to one year of his base salary, which is currently $231,000.
|
(b)
|
Equity compensation is based on an acceleration of vesting of unvested restricted stock, which includes 886 shares issued on April 1, 2013 and 1,078 shares issued on April 1, 2014. The average closing market price of Earthstone’s common stock over the first five business days following the first public announcement of the exchange on May 16, 2014 was $27.96.
|
(c)
|
Perquisites and benefits are comprised of nine months of COBRA premiums. Estimated COBRA benefits are based on current monthly premium amounts multiplied by a factor of approximately 1.8 times and extended for a period of nine months.
|
Vote Required for Approval and Board Recommendation
The non-binding advisory proposal regarding the Severance Plan will be approved if the holders of a majority of Earthstone shares cast vote in favor of such proposal in person or by proxy at the special meeting, assuming a quorum is present. Abstentions are treated as votes against the proposal to approve the Severance Plan if such shares are otherwise present in person or by proxy at the special meeting. However, broker non-votes (or other failures to vote) will have no effect on the non-binding advisory proposal to approve the Severance Plan.
THE BOARD OF DIRECTORS UNANIMOUSLY RECOMMENDS THAT THE EARTHSTONE STOCKHOLDERS
VOTE “FOR” THE NON-BINDING ADVISORY PROPOSAL TO APPROVE THE SEVERANCE PLAN.
EARTHSTONE’S EXECUTIVE COMPENSATION AND OTHER TRANSACTIONS
Summary Compensation Table
The following table sets forth the compensation of Earthstone’s chief executive and financial/accounting officers for the fiscal years ended March 31, 2014 and 2013. No other executive officer of Earthstone received total compensation in excess of $100,000 during that period. In accordance with the rules of the SEC, the compensation described in this table does not include (i) medical, group life insurance or other benefits received by any of the named executive officers that are available generally to all of Earthstone’s salaried employees or (ii) perquisites and other personal benefits received by the named executive officers that in the aggregate do not exceed $10,000.
|
|
|
|
|
|
|
|
|
|
Incentive Plan Compensation1
|
|
|
All Other Compensation
|
|
|
|
|
|
|
2014
|
|
$ |
231,000 |
|
|
$ |
— |
|
|
$ |
188,923 |
|
|
|
9,495 |
|
|
$ |
429,418 |
|
President and Chief Executive Officer |
|
2013
|
|
|
231,000 |
|
|
|
— |
|
|
|
55,032 |
|
|
|
7,354 |
2 |
|
|
293,386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Paul D. Maniscalco
|
|
2014
|
|
|
34,250 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
34,250 |
|
Interim Chief Financial Officer |
|
2013
|
|
|
11,969 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
11,969 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jim Poage
|
|
2014
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Interim Chief Financial Officer
|
|
2013
|
|
|
10,275 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
10,275 |
|
_______________________________
1
|
Includes $188,923 and $55,032 earned for the fiscal years ended March 31, 2014 and 2013, respectively, under the Performance Bonus Plan (described below). Amount also includes $0 and $0 for the fiscal years ended March 31, 2014 and 2013, respectively, in each case pursuant to the terms and conditions of Earthstone’s Oil and Gas Incentive Compensation Plan (described below). During the fiscal year ended March 31, 2013, $47,520 was paid to Mr. Singleton related to amounts earned pursuant to the Oil and Gas Incentive Compensation Plan during the fiscal year ended March 31, 2012.
|
2
|
Amounts include (i) matching funds contributed by Earthstone to Mr. Singleton’s 401(k) plan account of $8,019 and $6,014 for the fiscal years ended March 31, 2014 and 2013, respectively, and (ii) $1,476 and $1,340 for premiums paid by Earthstone on a life insurance policy for Mr. Singleton during fiscal 2014 and 2013, respectively, which provides for payment of a death benefit to Mr. Singleton’s designated beneficiary.
|
Financial Consulting Agreement – The material terms of Mr. Maniscalco’s consulting agreement dated November 11, 2012, includes compensation for services provided based on an hourly rate of pay as well as reimbursement for out-of-pocket direct expenses.
Financial Consulting Agreement – The material terms of Mr. Poage’s consulting agreement, dated March 25, 2011, includes compensation for services provided based on an hourly rate of pay as well as reimbursement for out-of-pocket direct expenses.
Performance Bonus Plan – The Performance Bonus Plan provides for a potential cash bonus for Earthstone’s Chief Executive Officer each fiscal year equal to a maximum of 100% of his annual salary. The bonus is determined based on four criteria, each contributing up to a maximum of 25% of the bonus. The four criteria are (i) increase in annual production; (ii) increase in reserves; (iii) return on investment; and (iv) performance of Earthstone’s stock price relative to the stock prices of Earthstone’s peers. The percentage awards from each criterion are added to determine the total percentage of the award. Each of these criteria and the peer companies are discussed below.
Annual Production Bonus Award Percentage. The Compensation Committee believes that increasing production is a critical measure of Earthstone’s performance, and, therefore, the Chief Executive Officer’s performance. For purposes of the Performance Bonus Plan, the annual increase in production is determined by dividing the annual production in barrels of oil equivalent (BOE) for the most recent fiscal year by the annual production in BOE for the prior fiscal year and then subtracting 100%. For each percentage increase in annual production, the bonus award is 2% of the Chief Executive Officer’s salary, subject to a maximum percentage award of 25%. For the fiscal year ended March 31, 2014, Mr. Singleton was awarded the full 25% of the annual production bonus award percentage for increasing production by 46.3%. For the fiscal year ended March
31, 2013, Mr. Singleton was not awarded any amounts related to the annual production bonus as production declined.
Reserves Bonus Award Percentage. The Compensation Committee believes that increasing Earthstone’s reserve base is critical to Earthstone’s future growth. Furthermore, the Compensation Committee believes that it is critical to not only replace those reserves that have been depleted, but to grow reserves year-over-year despite normal depletion. The Compensation Committee is aware that commodity prices have an influence on reserves that are beyond the control of the Chief Executive Officer. The Compensation Committee believes this limitation is acceptable, because in those years when commodity prices are up and have a positive effect on bonus determination, Earthstone is more likely to have the funds to pay bonuses, and in years that commodity prices are down and have a negative effect on bonus determination, Earthstone is less likely to have the funds to pay bonuses. For each percentage
increase in reserves, the bonus award is 2% of the Chief Executive Officer’s salary, subject to a maximum percentage award of 25%. Mr. Singleton received 25% of the eligible 25% during the fiscal year ended March 31, 2014 related to a 27.3% increase in Proved Developed Producing BOE during the fiscal year. Mr. Singleton received 14.4% of the eligible 25% during the fiscal year ended March 31, 2013 related to a 7.2% increase in Proved Developed Producing BOE during the fiscal year.
Return on Investment Bonus Award Percentage. The Compensation Committee believes that it is important to balance the Chief Executive Officer’s incentive to increase production and reserves with a metric that rewards the effectiveness of those increases. This Return on Investment (“ROI”) metric is intended to evaluate capital expenditures in a given year (or multiple years in the case of multi-year projects or those projects that overlap a year-end) versus the anticipated cash flow, if any, that those projects, on an aggregate basis, are expected to generate in the future. For each percentage increase in return on investment in excess of 8% (Earthstone’s approximate cost of funds), the bonus award is 2% of the Chief Executive Officer’s salary, subject to a maximum percentage award of 25%. For the fiscal year ended March 31,
2014, Mr. Singleton received 16.2% of the ROI award for generating a return on investment of 16.1% on Earthstone’s capital expenditures, exceeding the 8% minimum threshold by 8.1%. For the fiscal year ended March 31, 2013, Mr. Singleton was not awarded any amounts related to the annual ROI award in that the calculated return on investment did not exceed 8%.
Stock Price Bonus Award Percentage. The Compensation Committee believes that, in addition to production, reserves and ROI, the Chief Executive Officer should focus on the fundamentals of the business, net income and EBITDA. Furthermore, the Compensation Committee believes that the market will reward solid, consistent growth in these areas. For this reason, the Compensation Committee has chosen stock price as the metric most suitable for rewarding consistent improvement in the fundamentals of the business. The Compensation Committee has determined it appropriate to balance this metric against the other three and limit this award component to 25%.
The percentage increase or decrease in Earthstone’s stock price is evaluated relative to Earthstone’s peers on a quartile basis. The increase or decrease shall be determined for both Earthstone and each peer by taking the arithmetic average of the closing price per share for the last ten trading days of the fiscal year evaluated and dividing it by the arithmetic average of the closing price per share for the last ten trading days of the preceding fiscal year. The resulting percentage is adjusted by subtracting one hundred percent (100%) to determine the percentage increase or decrease in Earthstone’s and each peer’s stock price.
Share prices will be adjusted for any stock split or other recapitalization, if any. Earthstone’s and the peers’ stock performance shall be ranked from highest to lowest. Given seven peers, plus Earthstone, the four quartiles will contain two companies each. The share price bonus award percentage is based on which quartile Earthstone occupies. Each quartile provides a bonus award as follows:
|
|
|
|
|
First Quartile
|
|
100.0% of 25%
|
|
25.000% |
Second Average Quartile
|
|
62.5% of 25%
|
|
15.625% |
Third Average Quartile
|
|
37.5% of 25%
|
|
9.375% |
Fourth Quartile
|
|
0.0% of 25%
|
|
0.000% |
For the fiscal year ended March 31, 2014, Earthstone’s stock price performance was in the second quartile; thus, Mr. Singleton was awarded 15.625% of the stock price performance award. During the fiscal year ended March 31, 2013, Earthstone fell within the third quartile relative to the peers. The stock price award percentage was therefore 9.375% of the stock price performance award.
Performance Bonus Plan Summary. Having various percentages for each of the four bonus awards for the fiscal year ended March 31, 2014, Mr. Singleton earned a bonus of $188,923 or 81.79% of his salary for the year ended March 31, 2014 (i.e., $231,000). Having various percentages for each of the four bonus awards for the fiscal year ended March 31, 2013, Mr. Singleton earned a total bonus of $55,032 or 23.82% of his salary for the year ended March 31, 2013 (i.e., $231,000).
Peer Companies – Peer companies are selected by the Compensation Committee based on a number of factors, including, but not limited to, market capitalization, stock exchange, similarity of business model (i.e., producer/operator vs. pipeline/service company), availability of compensation data, location of producing assets, number of employees, location of headquarters and director/officer ownership.
For the fiscal year ended March 31, 2014, the Compensation Committee selected the following companies as peers:
●
|
Enerjex Resources, Inc.
|
●
|
Escalera Resources Co. (formerly known as Double Eagle Petroleum Co.)
|
●
|
Fieldpoint Petroleum Corporation
|
●
|
Lilis Energy, Inc. (formerly known as Recovery Energy, Inc.)
|
In addition to the seven companies named above, the Compensation Committee selected American Eagle Energy Corporation as an alternate peer. The alternate peer was not used and would only be utilized if one of the seven other peers noted above should, for any reason, no longer be qualified or usable as a peer.
Oil and Gas Incentive Compensation Plan – Earthstone’s Oil and Gas Incentive Compensation Plan (the “O&G Plan”) became effective on April 1, 1980, and was amended in December 1982. The O&G Plan is a profit sharing plan for key employees of Earthstone. Historically, newly drilled properties were added to the plan and profits from those wells formed the basis for awards in the form of distributions to participants depending on that participant’s level of vesting and other factors. The O&G Plan also states that should an O&G Plan property be sold, participants in that property will receive their distribution percentage of the sales proceeds. No properties have been added to the O&G Plan since 1988 and the Compensation Committee has no plans to utilize the O&G Plan to make additional awards; however, the O&G Plan continues to make profit sharing distributions pursuant
to awards made prior to that date. Through March 2012, of the five participants receiving distributions, Mr. Singleton was the only current employee receiving distributions from the O&G Plan.
Following March 31, 2012, pursuant to the terms of the O&G Plan, Mr. Singleton was no longer a participant and therefore received no further compensation. During the fiscal year ended March 31, 2012, Earthstone sold one of its O&G Plan properties in which Mr. Singleton was a participant. Pursuant to the terms of the plan, Mr. Singleton received a percentage of the sales price equal to his participation percentage in that property. Going forward, Earthstone expects to receive positive and negative adjustments related to periods prior to the sale that will flow through to Mr. Singleton. Such amounts are expected to be de minimis in magnitude. As a result of the foregoing, for the fiscal years ended March 31, 2014 and 2013,
Mr. Singleton earned $0 and $0, respectively. It is not expected that Mr. Singleton will be compensated by future O&G Plan disbursements. Of the $66,571 earned during the fiscal year ended March 31, 2012, $47,520 was paid to Mr. Singleton during the fiscal year ended March 31, 2013.
401(k) Plan – In October 1997, Earthstone implemented a savings plan that allows participants to make contributions by salary reduction pursuant to Section 401(k) of the Code. Employees are required to be employed by Earthstone or a subsidiary of Earthstone for one year prior to becoming eligible to participate in the 401(k) Plan. Earthstone matches 100% of each employee’s contribution to the 401(k) Plan up to 3% of the employee’s salary. Contributions vest immediately. Contributions to the 401(k) Plan on behalf of Mr. Singleton are included in the All Other Compensation column in the Summary Compensation Table above.
Outstanding Equity Awards at Fiscal Year End
In July 2011, Earthstone adopted the 2011 Equity Incentive Compensation Plan (the “2011 Plan”). The 2011 Plan allows up to 150,000 shares of Earthstone’s common stock to be issued to personnel under the plan. During the year ended March 31, 2014, 5,013 shares of common stock were granted to employees of Earthstone. Subsequent to the grants, 2,713 shares of common stock were forfeited. As of March 31, 2014, there were approximately 138,959 shares of common stock available for issuance under the 2011 Plan.
The Earthstone Board adopted a Director Compensation Plan, effective April 1, 2007, which provides for a combination of cash and equity incentive compensation to attract and retain qualified and experienced director candidates. Up to 50,728 shares were reserved for issuance under the plan.
Pursuant to the plan, each non-employee director is entitled to receive an annual cash retainer of $16,000, together with $2,000 for attending each regular quarterly meeting of the Earthstone Board and each all-day special meeting of the Earthstone Board and $500 for each half-day special meeting of the Earthstone Board or one of its committees. No committee fees are payable for attendance by a director at a committee meeting held in conjunction with a regular quarterly or all-day special meeting of the Earthstone Board. The chairman of each of the Audit, Compensation and Nominating Committees receives an annual cash retainer of $5,500, $4,500 and $3,500, respectively.
In addition, non-employee directors receive $500 for attending committee meetings, unless the committee meeting is held in conjunction with a quarterly regular or all-day board meeting. Earthstone also reimburses reasonable expenses incurred by non-employee directors associated with attending board and committee meetings. Mr. Singleton, as an employee director, does not receive compensation for his service as a member of the Earthstone Board. In addition, each non-employee director receives an annual grant of restricted stock having a fair market value equal to $36,000 on April 1 of each year, based on the average closing price for the ten trading days preceding April 1 of each year. Grants of restricted stock vest one-third each year over three years. If a director terminates his or her participation on the Board prior to the time that the restricted stock is fully vested, the unvested portion of the award is forfeited and
reverts back to Earthstone. All shares of restricted stock will become vested upon the occurrence of a change of control, including pursuant to the proposed exchange.
The Earthstone Board requires that each restricted stock award recipient, within three years of the date that he or she becomes a member of the Board, own an amount of common stock equal to one year of his average total board compensation.
The following table sets forth information concerning the compensation of non-employee directors during the fiscal year ended March 31, 2014.
Director Compensation
|
|
Fees Earned or Paid in Cash
|
|
|
|
|
|
Richard K. Rodgers
|
|
$
|
34,500
|
2
|
|
$
|
36,000
|
|
$
|
70,500
|
Monroe W. Robertson
|
|
|
35,500
|
3
|
|
|
36,000
|
|
|
71,500
|
Andrew P. Calerich
|
|
|
33,500
|
4
|
|
|
36,000
|
|
|
69,500
|
Total
|
|
$
|
103,500
|
|
|
$
|
108,000
|
|
$
|
211,500
|
1
|
Represents the dollar amount recognized for financial statement reporting purposes for the fiscal year. Grants of shares of restricted stock vest one-third each year over three years. The number of shares included in each grant is determined based upon the average closing price for the ten trading days preceding each anniversary date of the original grant. The amounts shown do not reflect compensation actually received by directors or the actual value that may be recognized by directors with respect to these awards in the future, because each award is subject to forfeiture. The aggregate number of stock awards outstanding and subject to vesting at the fiscal year end March 31, 2014 for each director was as follows: Rodgers – 3,894 shares, Robertson – 3,894, and Calerich – 3,894. In addition, each director was granted 1,679 shares of restricted stock on April
1, 2014, subject to vesting and forfeiture.
|
2
|
Consists of a $16,000 annual cash retainer, $14,000 for attending Board and Committee meetings and $4,500 for serving as the Chairman of the Compensation Committee.
|
3
|
Consists of a $16,000 annual cash retainer, $14,000 for attending Board and Committee meetings and $5,500 for serving as the Chairman of the Audit Committee.
|
4
|
Consists of a $16,000 annual cash retainer, and $14,000 for attending Board and Committee meetings and $3,500 for serving as Chairman of the Nominating Committee.
|
Employment Contracts and Termination of Employment Arrangements
Earthstone has no employment contracts with any of its executive officers. Prior to the authorization of the exchange agreement, Earthstone also had no compensatory plan or arrangement with respect to any executive officer where such plan or arrangement would result in payments to such officer upon or following his resignation, retirement, or other termination of employment with Earthstone and its subsidiaries, or as a result of a change in control of Earthstone or a change in the executive officers’ responsibilities following a change in control. However, in connection with the adoption of the exchange agreement, the Earthstone Board adopted an Employee Severance Compensation Plan described in “Summary of Principal Terms of the 2014 Plan.”
It is expected that Mr. Singleton will continue to be an officer and director of Earthstone following the exchange.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT OF EARTHSTONE
The following table contains information about the beneficial ownership of the Earthstone common stock as of September 15, 2014 by:
●
|
each of the current Earthstone directors;
|
●
|
each executive officer named in the Summary Compensation Table; and
|
●
|
all Earthstone directors and current executive officers as a group.
|
Name of Beneficial Owner¹
|
|
Amount and Nature of Beneficial Ownership
|
|
|
|
|
|
|
|
453,360 |
|
|
|
26.1 |
% |
Jim Poage
|
|
|
— |
|
|
|
— |
|
Paul D. Maniscalco
|
|
|
— |
|
|
|
— |
|
Richard Rodgers
|
|
|
15,938 |
3 |
|
|
1.0 |
% |
Monroe Robertson
|
|
|
22,684 |
3 |
|
|
1.3 |
% |
Andrew Calerich
|
|
|
8,124 |
3 |
|
|
* |
|
Total for all officers and directors (six individuals)3
|
|
|
500,106 |
|
|
|
28.8 |
% |
*
|
The percentage of common stock beneficially owned is less than 1%.
|
1
|
The address of each of these persons is c/o Earthstone Energy, Inc., 633 Seventeenth Street, Suite 2320, Denver, Colorado 80202.
|
2
|
Based on 1,737,420 shares of common stock outstanding at the close of business on September 15, 2014, which reflects the forfeiture of 571 shares of common stock since the signing of the exchange agreement by a former employee of Earthstone.
|
3
|
Share ownership includes a total of 11,078 shares of restricted stock subject to vesting. The aggregate number of restricted stock awards outstanding and subject to vesting as of September 15, 2014 for each non-employee director was as follows: Robertson – 3,678 shares; Rodgers – 3,678; and Calerich – 3,678. Amounts include the 1,679 votable shares of restricted stock granted to each director on April 1, 2014. While restricted, such shares are subject to restrictions on the sale of such shares, which lapse in equal annual installments over a three-year period for each grant and are subject to forfeiture. All shares of restricted stock will become vested upon the occurrence of a change of control, including pursuant to the proposed exchange.
|
PRO FORMA BENEFICIAL OWNERSHIP UPON COMPLETION OF THE EXCHANGE
The following table contains information about the beneficial ownership of the Earthstone common stock upon consummation of the exchange by:
●
|
each person or group who is known to the management of Earthstone and Oak Valley to become the beneficial owner of more than 5% of the outstanding shares of common stock of the combined company upon consummation of the exchange;
|
●
|
each person expected to be a director or executive officer of the combined company; and
|
●
|
all directors and executive officers of the combined company as a group.
|
Name and Address of Beneficial Owner (a)
|
|
Amount of Shares and Nature of Beneficial Ownership
|
|
|
|
|
Oak Valley Resources, LLC (c)
|
|
|
9,124,452 |
|
|
|
84.0 |
% |
|
|
|
9,124,452 |
|
|
|
84.0 |
% |
|
|
|
453,360 |
|
|
|
4.2 |
% |
Jay F. Joliat (f)
|
|
|
42,479 |
|
|
|
* |
|
Douglas E. Swanson, Jr. (g)
|
|
|
9,124,452 |
|
|
|
84.0 |
% |
Brad A. Thielemann (g)
|
|
|
9,124,452 |
|
|
|
84.0 |
% |
Zachary G. Urban (h)
|
|
|
683,059 |
|
|
|
6.3 |
% |
Robert L. Zorich (g)
|
|
|
9,124,452 |
|
|
|
84.0 |
% |
All officers and directors as a group (i)
|
|
|
9,577,812 |
|
|
|
88.2 |
% |
*
|
The percentage of common stock beneficially owned is less than 1%.
|
(a)
|
Except as otherwise indicated below, the address and telephone number of each beneficial owner is c/o Oak Valley Resources, LLC, 110 Cypress Station Drive, Suite 220, Houston, TX 77090 and (281) 298-4246, respectively.
|
(b)
|
Upon consummation of the exchange, 9,124,452 shares of Earthstone common stock will be issued to Oak Valley, and pro forma for the exchange agreement, Earthstone will have 10,861,872 issued and outstanding shares of common stock.
|
(c)
|
Assumes Oak Valley receives 9,124,452 shares of common stock of Earthstone.
|
(d)
|
Mr. Lodzinski, as a member of the board of managers of Oak Valley, may be deemed to indirectly beneficially own the shares of Earthstone common stock to be held by Oak Valley. Mr. Lodzinski disclaims beneficial ownership of these shares, except to the extent of his pecuniary interest. Oak Valley Management, LLC (“OVM”) has a direct ownership of 2.6% in Oak Valley resulting in an indirect ownership of 238,901 shares of Earthstone on a post-exchange basis. Mr. Lodzinski is the sole manager of OVM and a member of the board of managers of Oak Valley, and will be a member of Earthstone’s board of directors. Mr. Lodzinski and his family members own 100% of Azure Energy, LLC (“Azure”), which in turn owns 28.4% of OVM, resulting in the indirect ownership of 67,966 additional shares of Earthstone. Because of his direct and indirect pecuniary interest in these shares, they may be deemed to be beneficially owned by Mr. Lodzinski.
|
(e)
|
Mr. Singleton’s address is c/o Earthstone Energy, Inc., 633 Seventeenth Street, Suite 2320, Denver, CO 80202.
|
(f)
|
Mr. Joliat is not a manager of Oak Valley but will become a director of Earthstone. The Jay F. Joliat Revocable Living Trust has a 0.5% direct ownership in Oak Valley, resulting in 42,479 Earthstone shares attributable to him indirectly through Oak Valley.
|
(g)
|
Following the exchange, five affiliated investment funds, specifically EnCap Energy Capital Fund VII, L.P., EnCap Energy Capital Fund VI, L.P., EnCap VI-B Acquisition, L.P., EnCap Energy Capital Fund V, L.P., and EnCap Energy Capital Fund V-B Acquisitions, L.P., each a Texas limited partnership, collectively own 58.8% of the Class A membership interests of Oak Valley. The EnCap funds are controlled indirectly by Messrs. Swanson, Thielemann and Zorich through their control of general partnerships that manage each of the five EnCap funds. The address of each EnCap fund is 1100 Louisiana, Suite 4900, Houston, Texas 77002.
|
|
Messrs. Swanson, Thielemann and Zorich are three of the five members of the board of managers of Oak Valley, and each will become a member of the board of directors of Earthstone following the exchange. Therefore, beneficial ownership of all Earthstone shares held by Oak Valley have been attributed to each of these three persons.
|
(h)
|
Mr. Urban will become a director of Earthstone. He is the CEO of Vlasic Group, which indirectly manages VILLco CAPITAL II, L.L.C., which has a 7.4% Class A membership interest in Oak Valley, resulting in 679,661 Earthstone shares owned indirectly through Oak Valley. Mr. Urban personally has a 0.04% direct ownership in Oak Valley, resulting in 3,398 Earthstone shares owned indirectly by him through Oak Valley.
|
(i)
|
Computed on the basis of direct or indirect beneficial ownership in accordance with Rule 13d-3 adopted under the Exchange Act but without duplication of ownership among the group.
|
DESCRIPTION OF SECURITIES OF EARTHSTONE
Earthstone’s current certificate of incorporation authorizes the issuance of up to 6,400,000 shares of common stock, which will increase to 100,000,000 if stockholders approve the amendment to the certificate of incorporation. As of the record date, _________ shares of common stock were issued and outstanding. All of the outstanding shares of common stock are fully paid and non-assessable.
Dividends. Holders of Earthstone common stock are entitled to receive ratably dividends out of funds legally available, if and when declared from time to time by Earthstone’s Board of Directors.
Liquidation; Dissolution. In the event of liquidation, dissolution or winding up of the affairs of Earthstone, holders of common stock are entitled to receive ratably and equally all of the assets of Earthstone remaining after the payment of liabilities and any preferential distributions payable to preferred stockholders, if any.
Preemptive Rights. The holders of common stock have no preemptive or conversion rights and are not subject to further calls or assessments.
Redemption. There are no redemption or sinking fund provisions applicable to the common stock.
The rights of the holders of the common stock are subject to any rights that may be fixed for holders of preferred stock, if any.
Under Earthstone’s certificate of incorporation, as amended, Earthstone’s Board of Directors currently has the authority to issue up to 600,000 shares of preferred stock, which will increase to 20,000,000 shares if stockholders approve the amendment to the certificate of incorporation. The Earthstone Board may, without further action by its stockholders, fix the rights (including voting rights), preferences, limitations and privileges of preferred shares that are issued. Such preferred stock may have rights, including economic rights, senior to those associated with Earthstone common stock. As a result, the issuance of preferred stock could have a material adverse effect on the price of Earthstone common stock, and the existence of a significant number
of shares of preferred stock available for issuance could make it more difficult for a third party to acquire a majority of Earthstone’s outstanding common stock.
Earthstone’s Board of Directors is expressly authorized at any time, and from time to time, to provide for the issuance of shares of preferred stock in one or more series, with such voting powers, full or limited, or without voting powers and with such designations, preferences and relative, participating, optional or other special rights, and qualifications, limitations or restrictions thereof, as shall be stated and expressed in the resolution or resolutions providing for the issue thereof adopted by the Board of Directors, subject to the limitations prescribed by law and in accordance with the provisions of Earthstone’s certificate of incorporation, including but not limited to the following:
(i)
|
the designation of the series and the number of shares to constitute the series;
|
(ii)
|
the dividend rate of the series, the conditions and dates upon which such dividends shall be payable, the relation which such dividends shall bear to the dividends payable on any other class or classes of stock, and whether such dividends shall be cumulative or noncumulative;
|
(iii)
|
whether the shares of the series shall be subject to redemption by Earthstone and, if made subject to such redemption, the times, prices and other terms and conditions of such redemption;
|
(iv)
|
the terms and amount of any sinking fund provided for the purchase or redemption of the shares of the series;
|
(v)
|
whether or not the shares of the series shall be convertible into or exchangeable for shares of any other class or classes or of any other series of any class or classes of stock of Earthstone, and, if provision shall be made for conversion or exchange, the times, prices, rates, adjustments and other terms and conditions of such conversion or exchange;
|
(vi)
|
the extent, if any, to which the holders of the shares of the series shall be entitled to vote with respect to the election of directors or otherwise;
|
(vii)
|
the restrictions, if any, on the issue or reissue of any additional preferred stock; and
|
(viii)
|
the rights of the holders of the shares of the series upon the dissolution, liquidation, or winding up of the corporation.
|
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires Earthstone’s directors and executive officers, and persons who own more than 10% of Earthstone’s common stock to file with the SEC initial reports of ownership and reports of changes in ownership of Earthstone’s common stock. Executive officers, directors and greater than 10% stockholders are required by SEC regulations to furnish Earthstone with copies of all Section 16(a) reports they file. To Earthstone’s knowledge, based solely on review of the copies of such reports furnished to Earthstone or advice that no filings were required during the year ended March 31, 2014, all executive officers, directors and greater than 10% beneficial owners complied with the Section 16(a) filing requirements.
FUTURE STOCKHOLDER PROPOSALS
Pursuant to Rule 14a-8 under the Exchange Act, stockholders may present proper proposals for inclusion in Earthstone’s proxy statement and for consideration at the next annual meeting of Earthstone’s stockholders by submitting their proposals to Earthstone in a timely manner. Earthstone intends to hold an annual meeting in 2014, although management currently expects the annual meeting to be more than 30 days after the anniversary date of the 2013 annual meeting. In order to be eligible for inclusion in Earthstone’s proxy materials pursuant to Rule 14a-8 under the Exchange Act for the 2014 annual meeting, if such meeting is held, written notice of any stockholder proposal must be received by Earthstone within a reasonable time before the company begins to print and mail its proxy materials for such annual meeting. In addition, Earthstone’s bylaws
currently provide that in order for a stockholder to nominate a candidate for election as a director at an annual meeting of stockholders or propose business for consideration at an annual meeting of stockholders, a stockholder’s notice to the Corporate Secretary must be delivered to or mailed and received at the principal executive offices of Earthstone not less than 90 days nor more than 120 days prior to the date of the meeting; provided, however, that in the event that public disclosure of the date of the meeting is first made less than 100 days prior to the date of the meeting, notice by the stockholder in order to be timely must be so received not later than the close of business on the tenth day following the day on which such public disclosure of the date of the meeting was made. Such notice shall be sent to Corporate Secretary, Earthstone Energy, Inc., 633 Seventeenth Street, Suite 2320, Denver,
Colorado 80202 or, if the exchange occurs, 110 Cypress Station Drive, Suite 220, Houston, Texas 77090, or the then-current office address.
In order to curtail controversy as to the date on which a proposal was received by Earthstone, it is suggested that proponents submit their proposals by certified mail-return receipt requested. Such proposals must also meet the other requirements established by the SEC for stockholder proposals.
OTHER BUSINESS
Earthstone knows of no other matters to be presented at the meeting. If any other matter properly comes before the meeting, the appointed proxies will vote the proxies in accordance with their best judgment.
WHERE YOU CAN FIND MORE INFORMATION
Earthstone files annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any reports, statements or other information Earthstone files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Earthstone’s SEC filings are also available to the public from commercial document retrieval services and at the website maintained by the SEC at www.sec.gov.
GLOSSARY OF OIL AND GAS TERMS
Unless otherwise indicated in this proxy statement, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
The following definitions shall apply to the technical terms used in this proxy statement:
Terms Used to Describe Quantities of Crude Oil and Natural Gas
“Bbl” – Barrel or 42 U.S. gallons liquid volume.
“BOE” – Barrels of crude oil equivalent.
“Condensate” – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Mcf” – Thousand cubic feet of gas.
Terms Used to Describe Interests in Wells and Acreage
“Gross acres” – The number of acres in which a gross working interest is owned.
“Gross well” – A well in which a working interest is owned.
“Net acres” – The percentage ownership of gross acreage. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).
“Net well” – Deemed to exist when the sum of fractional ownership working interests in gross wells equals one.
“Developed acreage” – Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Development well” – A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves.
“Disposal well” – A well used for the disposal of water resulting from the production of oil and gas. Oil and gas reservoirs are usually found in porous rocks, which also contain saltwater. This saltwater, which accompanies the oil and gas to the surface, is disposed over time through injection into underground porous rock formations not productive of oil or gas.
“Dry hole” – An exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.
“Exploratory well” – A well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir.
“Injector well” – A well used for the injection of water, gas, steam or CO2 into an oil or gas producing reservoir/unit in order to maintain reservoir pressure, heat the oil or lower its viscosity, in order to increase oil and/or gas recovery and to safely dispose of the salt and/or fresh water produced with oil and natural gas.
“Productive well” – An exploratory or a development well that is not a dry hole.
“Undeveloped acreage” – Leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. Undeveloped acreage includes net acres under the bit until a productive well is established in the spacing unit.
“Unproved property” – A property or part of a property with no proved reserves.
“Unsuccessful efforts” – Drilling activities that result in a dry hole. Costs associated with unsuccessful efforts are part of the cost to discover reserves, therefore are capitalized in the full cost pool but are expensed under the successful efforts method of accounting.
Terms Used To Describe Seismic Activity and Operations
“Fracturing” – The injection of water, sand and additives under hydraulic pressure into prospective rock formations at depth to stimulate oil and natural gas production.
“Horizontal drilling” – A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontal within a designated zone typically defined as the prospective pay zone to be completed for oil and/or gas.
“Hydraulic stimulation technology” – A synonym for “fracturing.” A process that results in the creation of fractures in rocks. The fracturing is done from a wellbore drilled into reservoir rock formations at depth to increase the rate and ultimate recovery of oil and natural gas.
“Plugging and abandonment” – The sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
“Recompletion” – The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“Workover” – Operations on a producing well to restore or increase production.
Terms Used To Describe the Legal Ownership of Oil and Natural Gas Properties
“Revenue interest” – The amount or percentage of revenue/proceeds derived from a producing well that the owner is entitled to receive.
“Working interest” – The amount or percentage of costs that an owner is required to pay of drilling and production expenses. It also gives the owners, in the aggregate, the right to drill, produce and conduct operating activities on the property.
Terms Used To Assign a Present Value To or To Classify Reserves
“PV-10” – The estimated future cash flow, discounted at a rate of 10% per annum, with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the U.S. Securities and Exchange Commission.
“Proved developed non-producing reserves” – Proved crude oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
“Proved developed reserves” – Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“Proved reserves” – Proved crude oil and natural gas reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped reserves” – Proved undeveloped oil and gas are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
“Standardized measure” – The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.
Other Terms
“Farmout” – An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin,” while the interest transferred by the assignor is a “farmout.”
“Field” – An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
“Play” – An accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area expanse.
“Prospect” – A location where hydrocarbons such as oil and gas are believed to be present in quantities which are economically feasible to produce.
“Reservoir” – A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Resources” – Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL INFORMATION
OF EARTHSTONE ENERGY, INC.
Introduction
On May 15, 2014, Earthstone Energy, Inc., a Delaware corporation (“Earthstone” or the “Company”), and Oak Valley Resources, LLC (“OVR”), a Delaware limited liability company, entered into an Exchange Agreement (the “Exchange Agreement”), whereby OVR will contribute to Earthstone the membership interests of its three wholly-owned subsidiaries, Oak Valley Operating, LLC, EF Non-Op, LLC and Sabine River Energy, LLC, each a Texas limited liability company (collectively, “Oak Valley”), inclusive of producing assets, undeveloped acreage and an estimated $139.1 million of cash, in exchange for the issuance of approximately 9.1 million shares of Earthstone common stock, par value $0.001 per share (the “Common Stock”), to OVR (the “Exchange”). The
specified amount of cash represents existing cash on hand plus approximately $107 million of capital commitments available to OVR from its members in accordance with the terms of its limited liability company agreement. The Exchange Agreement contractually obligates OVR to deliver its existing cash balances and the capital commitments from its members to Earthstone. The Exchange Agreement and the Exchange have been approved by the board of directors of Earthstone (the “Board”) and the board of managers of OVR.
OVR, the parent company of Oak Valley, prior to the Exchange, has on its balance sheet cash, the membership interests of Oak Valley, the outstanding balance on the Oak Valley Resources Amended and Restated Credit Agreement (“OVR Credit Agreement”), the associated deferred financing costs and commodity derivative instruments. OVR also has commitments from its members to contribute capital of approximately $107 million. In the Exchange, OVR will pay off its outstanding balance on the OVR Credit Agreement, which is backed by the assets of Oak Valley, and amend the OVR Credit Agreement to transfer it to Earthstone. OVR will also transfer the open commodity derivative contracts, which are provided for under the OVR Credit Agreement, to Earthstone. As noted above, OVR will contribute the membership interests of Oak Valley and any remaining
cash on hand plus the cash from its members’ capital commitments to Earthstone in the Exchange. Subsequent to the Exchange, OVR will hold the newly issued shares of Earthstone and will retain no other significant assets or liabilities.
Following the Exchange, current Earthstone stockholders will own 16% and OVR will own 84% of the Company’s outstanding Common Stock, and six of the seven members of the Board will be persons who are affiliated with OVR. It is anticipated that the Exchange will be accounted for as a “reverse acquisition” and recapitalization since OVR will have control, both quantitatively and qualitatively, over the combined company.
The following unaudited pro forma condensed consolidated combined financial statements reflect the historical consolidated results of Earthstone and Oak Valley, on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on June 30, 2014 for pro forma balance sheet purposes, and on January 1, 2013 for pro forma statements of operations purposes:
●
|
Purchase Accounting Adjustment. Although Earthstone (the public company) is the legal acquirer, Oak Valley (the private company) will be the accounting acquirer. Accordingly, the assets and liabilities of Earthstone are recorded at their preliminary estimated fair values. The actual adjustments to the consolidated combined financial statements upon consummation of the Exchange and allocation of the purchase price will depend on a number of factors, including additional financial information available at such time, changes in the fair value of Earthstone’s Common Stock transferred at the closing date, changes in the estimated fair value of Earthstone’s oil and natural gas properties as of the closing date, and changes in the operating results of Earthstone between the date of this pro forma information and the closing date of the Exchange. Accordingly, the final allocations of Exchange
consideration and the effects of such allocations on the results of operations may differ materially from the preliminary allocations and unaudited pro forma combined amounts included herein.
|
●
|
Subsequent to the Exchange, Earthstone will follow the Successful Efforts method of accounting; Earthstone currently follows the Full Cost method of accounting. The Purchase Accounting Adjustment includes adjustments related to depletion for this change in method of accounting for Earthstone. For further information see Note 1 Basis of Presentation to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements.
|
●
|
The Eagle Ford Acquisition. In July 2013 and August 2013, Oak Valley purchased producing wells and acreage in the Eagle Ford shale trend of Texas (the “Eagle Ford Properties”) for a combined consideration of approximately $87.0 million (the “Eagle Ford Acquisition”).
|
●
|
Exchange Related Transactions. Pursuant to the terms of Exchange, Oak Valley Operating, LLC, EF Non-Op, LLC and Sabine River Energy, LLC will become direct subsidiaries of Earthstone and, as a result, will become subject to U.S. federal and state income taxes as a subchapter C corporation under the Internal Revenue Code of 1986, as amended. In addition, cash of the combined companies will be used to repay all of Earthstone’s and Oak Valley’s debt outstanding upon closing of the Exchange.
|
●
|
As noted above, Earthstone will follow the Successful Efforts method of accounting; Exchange Related Transactions includes adjustments related to the expensing of costs previously capitalized by Earthstone under the Full Cost method of accounting.
|
Earthstone’s fiscal year end is March 31 and Oak Valley’s fiscal year end is December 31. After the Exchange, Earthstone will change its fiscal year end to December 31; however, the fiscal years are not being conformed for the purpose of presenting pro forma condensed consolidated combined financial statements, pursuant to Rule 11-02(c)(3) of Regulation S-X, because the two fiscal year ends are not separated by more than 93 days.
The unaudited pro forma condensed consolidated combined balance sheet of the Company is based on the unaudited historical consolidated balance sheets of Earthstone and Oak Valley as of June 30, 2014. The balance sheet includes pro forma adjustments to give effect to the Purchase Accounting Adjustment and Exchange Related Transactions as if they had occurred on June 30, 2014.
The unaudited pro forma condensed consolidated combined statements of operations of the Company are based on (i) the unaudited historical consolidated statements of operations of Earthstone and Oak Valley for the six months ended June 30, 2014, having given effect to the Purchase Accounting Adjustment and Exchange Related Transactions as if they had occurred on January 1, 2013; (ii) the audited historical consolidated statements of operations of Earthstone for the twelve months ended March 31, 2014 and the audited historical consolidated statements of operations of Oak Valley for the twelve months ended December 31, 2013, having given effect to
the Purchase Accounting Adjustment, Eagle Ford Acquisition and Exchange Related Transactions as if they had occurred on January 1, 2013; (iii) the historical statements of revenues and direct operating expenses of the Eagle Ford Properties, as included elsewhere in this proxy statement; and (iv) the historical accounting records of Earthstone and Oak Valley. The Earthstone historical information included in the unaudited pro forma condensed consolidated combined statement of operations for the six months ended June 30, 2014 is derived by subtracting Earthstone’s unaudited consolidated statements of operations for the nine months ended December 31, 2013 from its audited historical consolidated statements of operations for the twelve months ended March 31, 2014
and adding the unaudited statement of operations for three months ended June 30, 2014.
The pro forma data presented reflects events directly attributable to the described transactions and certain assumptions the Company believes are reasonable. The pro forma data is not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated above or which could be achieved in the future. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual adjustments may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial statements.
The unaudited pro forma condensed consolidated combined financial statements are provided for illustrative purposes only and are not intended to represent or be indicative of the consolidated results of operations or financial position of Earthstone that would have been recorded had the Exchange been completed as of the dates presented and should not be taken as representative of future results of operations or financial position of Earthstone. The unaudited pro forma condensed consolidated combined financial statements do not reflect the impact of any potential operational efficiencies, asset dispositions, cost savings or economies of scale that Earthstone may achieve with respect to the combined operations. Additionally, the pro forma statements of operations do not include non-recurring charges or credits and the related tax effects which result directly from the Exchange. Certain reclassifications for the six and twelve
month periods ended June 30, 2014 and March 31, 2014 have been made to Earthstone’s historical financial statements presented in this proxy statement to conform to Oak Valley’s historical presentation. Certain workover expenses previously included in the Lease operating expense line item on the Statement of Operations have been reclassified to the line item Workover, well service and water-disposal expense. Certain reclassifications for the six and twelve month periods ended June 30, 2014 and December 31, 2013, respectively, have been made to Oak Valley’s historical presentation: operating expenses related to gathering activities have been reclassified from Lease operating expense to the line item Workover, well service and water disposal expense on the Statement of Operations.
The unaudited pro forma condensed consolidated combined financial statements have been derived from and should be read in conjunction with the historical consolidated financial statements and accompanying notes included in this proxy statement under “Financial Statements of Earthstone, Inc.” and “Financial Statements of Oak Valley Resources, LLC.”
Earthstone Energy, Inc.
Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet
|
|
|
|
|
|
|
|
Purchase
|
|
|
Exchange
|
|
|
|
|
|
|
Earthstone
|
|
|
Oak Valley
|
|
|
Accounting
|
|
|
Related
|
|
|
Pro Forma
|
|
ASSETS
|
|
Historical
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Transactions
|
|
|
Combined
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
(a)
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
2,119,000 |
|
|
$ |
32,035,000 |
|
|
$ |
- |
|
|
$ |
88,195,000 |
(b)
|
|
$ |
122,349,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas
|
|
|
4,282,000 |
|
|
|
12,121,000 |
|
|
|
- |
|
|
|
- |
|
|
|
16,403,000 |
|
Joint interest owners and other
|
|
|
271,000 |
|
|
|
8,671,000 |
|
|
|
- |
|
|
|
- |
|
|
|
8,942,000 |
|
Short-term derivative instruments
|
|
|
- |
|
|
|
7,000 |
|
|
|
- |
|
|
|
- |
|
|
|
7,000 |
|
Prepaid expenses and other current assets
|
|
|
887,000 |
|
|
|
458,000 |
|
|
|
- |
|
|
|
- |
|
|
|
1,345,000 |
|
Total current assets
|
|
|
7,559,000 |
|
|
|
53,292,000 |
|
|
|
- |
|
|
|
88,195,000 |
|
|
|
149,046,000 |
|
PROPERTY, PLANT AND EQUIPMENT, AT COST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Properties
|
|
|
69,850,000 |
|
|
|
210,978,000 |
|
|
|
(9,450,000 |
) |
|
|
- |
|
|
|
271,378,000 |
|
Unproved Properties
|
|
|
687,000 |
|
|
|
45,334,000 |
|
|
|
- |
|
|
|
- |
|
|
|
46,021,000 |
|
Accumulated depreciation, depletion and amortization
|
|
|
(32,613,000 |
) |
|
|
(87,410,000 |
) |
|
|
32,613,000 |
|
|
|
- |
|
|
|
(87,410,000 |
) |
Total oil and natural gas properties, net
|
|
|
37,924,000 |
|
|
|
168,902,000 |
|
|
|
23,163,000 |
|
|
|
- |
|
|
|
229,989,000 |
|
Other property, plant and equipment, net
|
|
|
589,000 |
|
|
|
748,000 |
|
|
|
- |
|
|
|
- |
|
|
|
1,337,000 |
|
Total property, plant and equipment, net
|
|
|
38,513,000 |
|
|
|
169,650,000 |
|
|
|
23,163,000 |
|
|
|
- |
|
|
|
231,326,000 |
|
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term derivative instruments
|
|
|
- |
|
|
|
6,000 |
|
|
|
- |
|
|
|
- |
|
|
|
6,000 |
|
Goodwill
|
|
|
- |
|
|
|
- |
|
|
|
21,298,000 |
|
|
|
- |
|
|
|
21,298,000 |
|
Other long term assets
|
|
|
196,000 |
|
|
|
679,000 |
|
|
|
- |
|
|
|
(75,000 |
) (b) |
|
|
800,000 |
|
Total noncurrent assets
|
|
|
196,000 |
|
|
|
685,000 |
|
|
|
21,298,000 |
|
|
|
(75,000 |
) |
|
|
22,104,000 |
|
TOTAL ASSETS
|
|
$ |
46,268,000 |
|
|
$ |
223,627,000 |
|
|
$ |
44,461,000 |
|
|
$ |
88,120,000 |
|
|
$ |
402,476,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$ |
5,691,000 |
|
|
$ |
18,650,000 |
|
|
$ |
- |
|
|
$ |
1,325,000 |
(e) |
|
$ |
25,666,000 |
|
Revenue and royalties payable
|
|
|
- |
|
|
|
17,566,000 |
|
|
|
- |
|
|
|
- |
|
|
|
17,566,000 |
|
Short-term derivative instruments
|
|
|
- |
|
|
|
1,273,000 |
|
|
|
- |
|
|
|
- |
|
|
|
1,273,000 |
|
Asset retirement obligations
|
|
|
320,000 |
|
|
|
67,000 |
|
|
|
- |
|
|
|
- |
|
|
|
387,000 |
|
Advances
|
|
|
- |
|
|
|
18,961,000 |
|
|
|
- |
|
|
|
- |
|
|
|
18,961,000 |
|
Total current liabilities
|
|
|
6,011,000 |
|
|
|
56,517,000 |
|
|
|
- |
|
|
|
1,325,000 |
|
|
|
63,853,000 |
|
NONCURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
8,000,000 |
|
|
|
10,825,000 |
|
|
|
- |
|
|
|
(18,825,000 |
) (b) |
|
|
- |
|
Asset retirement obligations
|
|
|
2,126,000 |
|
|
|
3,093,000 |
|
|
|
- |
|
|
|
- |
|
|
|
5,219,000 |
|
Deferred tax liability
|
|
|
4,695,000 |
|
|
|
- |
|
|
|
11,170,000 |
|
|
|
14,016,000 |
(d) |
|
|
29,881,000 |
|
Total noncurrent liabilities
|
|
|
14,821,000 |
|
|
|
13,918,000 |
|
|
|
11,170,000 |
|
|
|
(4,809,000 |
) |
|
|
35,100,000 |
|
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members' equity
|
|
|
- |
|
|
|
153,192,000 |
|
|
|
- |
|
|
|
(153,192,000 |
) (c) |
|
|
- |
|
Common stock
|
|
|
18,000 |
|
|
|
- |
|
|
|
2,000 |
|
|
|
- |
|
|
|
11,000 |
|
|
|
|
|
|
|
|
|
|
|
|
(18,000 |
) |
|
|
9,000 |
(c) |
|
|
|
|
Additional paid-in capital
|
|
|
23,481,000 |
|
|
|
- |
|
|
|
58,725,000 |
|
|
|
153,183,000 |
(c) |
|
|
318,928,000 |
|
|
|
|
- |
|
|
|
- |
|
|
|
(23,481,000 |
) |
|
|
107,020,000 |
(b) |
|
|
|
|
Treasury Stock
|
|
|
(458,000 |
) |
|
|
- |
|
|
|
458,000 |
|
|
|
- |
|
|
|
- |
|
Accumulated earnings (deficit)
|
|
|
2,395,000 |
|
|
|
- |
|
|
|
(2,395,000 |
) |
|
|
(75,000 |
) (b) |
|
|
(15,416,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,016,000 |
) (d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,325,000 |
) (e) |
|
|
|
|
Total equity
|
|
|
25,436,000 |
|
|
|
153,192,000 |
|
|
|
33,291,000 |
|
|
|
91,604,000 |
|
|
|
303,523,000 |
|
TOTAL LIABILITIES AND EQUITY
|
|
$ |
46,268,000 |
|
|
$ |
223,627,000 |
|
|
$ |
44,461,000 |
|
|
$ |
88,120,000 |
|
|
$ |
402,476,000 |
|
The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.
Earthstone Energy, Inc.
Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations
|
|
Earthstone
|
|
|
Oak Valley
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
Historical
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
|
Exchange
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(f)
|
|
|
|
|
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
8,373,000 |
|
|
|
16,376,000 |
|
|
|
- |
|
|
|
- |
|
|
$ |
24,749,000 |
|
Natural gas and natural gas liquid sales
|
|
|
1,582,000 |
|
|
|
7,260,000 |
|
|
|
- |
|
|
|
- |
|
|
|
8,842,000 |
|
Well service and water-disposal revenue
|
|
|
56,000 |
|
|
|
195,000 |
|
|
|
- |
|
|
|
- |
|
|
|
251,000 |
|
Total revenues
|
|
|
10,011,000 |
|
|
|
23,831,000 |
|
|
|
- |
|
|
|
- |
|
|
|
33,842,000 |
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,865,000 |
|
|
|
4,469,000 |
|
|
|
- |
|
|
|
27,000 |
(i) |
|
|
6,361,000 |
|
Exploration expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
310,000 |
(i) |
|
|
310,000 |
|
Production taxes
|
|
|
847,000 |
|
|
|
998,000 |
|
|
|
- |
|
|
|
- |
|
|
|
1,845,000 |
|
Workover, well service and water-disposal
|
|
|
408,000 |
|
|
|
373,000 |
|
|
|
- |
|
|
|
- |
|
|
|
781,000 |
|
Depreciation, depletion and amortization
|
|
|
2,224,000 |
|
|
|
7,763,000 |
|
|
|
(257,000 |
) |
|
|
- |
|
|
|
9,730,000 |
|
General and administrative expenses
|
|
|
1,906,000 |
|
|
|
3,214,000 |
|
|
|
- |
|
|
|
(975,000 |
) (j) |
|
|
4,145,000 |
|
Accretion of asset retirement obligations
|
|
|
105,000 |
|
|
|
151,000 |
|
|
|
- |
|
|
|
- |
|
|
|
256,000 |
|
Total operating expenses
|
|
|
7,355,000 |
|
|
|
16,968,000 |
|
|
|
(257,000 |
) |
|
|
(638,000 |
) |
|
|
23,428,000 |
|
OPERATING INCOME
|
|
|
2,656,000 |
|
|
|
6,863,000 |
|
|
|
257,000 |
|
|
|
638,000 |
|
|
|
10,414,000 |
|
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(109,000 |
) |
|
|
(297,000 |
) |
|
|
- |
|
|
|
109,000 |
(k) |
|
|
(297,000 |
) |
Derivative loss
|
|
|
- |
|
|
|
(2,303,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
(2,303,000 |
) |
Other income
|
|
|
12,000 |
|
|
|
7,000 |
|
|
|
- |
|
|
|
- |
|
|
|
19,000 |
|
Total other income (expense), net
|
|
|
(97,000 |
) |
|
|
(2,593,000 |
) |
|
|
- |
|
|
|
109,000 |
|
|
|
(2,581,000 |
) |
INCOME BEFORE INCOME TAXES
|
|
|
2,559,000 |
|
|
|
4,270,000 |
|
|
|
257,000 |
|
|
|
747,000 |
|
|
|
7,833,000 |
|
INCOME TAX (EXPENSE) BENEFIT
|
|
|
(473,000 |
) |
|
|
- |
|
|
|
(95,000 |
) |
|
|
(275,000 |
) (l) |
|
|
(2,842,000 |
) |
PRO FORMA TAX (EXPENSE) BENEFIT
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,999,000 |
) (m) |
|
|
|
|
NET INCOME
|
|
$ |
2,086,000 |
|
|
$ |
4,270,000 |
|
|
$ |
162,000 |
|
|
$ |
(1,527,000 |
) |
|
$ |
4,991,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.46 |
|
Diluted
|
|
$ |
1.21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHARES OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1,717,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,876,000 |
|
Diluted
|
|
|
1,721,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,876,000 |
|
The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.
Earthstone Energy, Inc.
Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations
|
|
|
|
|
|
|
|
Purchase
|
|
|
Eagle Ford
|
|
|
Exchange
|
|
|
|
|
|
|
Earthstone
|
|
|
Oak Valley
|
|
|
Accounting
|
|
|
Acquistion
|
|
|
Related
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Adjustments
|
|
|
Transactions
|
|
|
Combined
|
|
|
|
|
|
|
|
|
|
(f)
|
|
|
(g)
|
|
|
|
|
|
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
15,633,000 |
|
|
$ |
16,038,000 |
|
|
$ |
- |
|
|
$ |
17,914,000 |
|
|
$ |
- |
|
|
$ |
49,585,000 |
|
Natural gas and natural gas liquid sales
|
|
|
1,807,000 |
|
|
|
13,596,000 |
|
|
|
- |
|
|
|
434,000 |
|
|
|
- |
|
|
|
15,837,000 |
|
Well service and water-disposal revenue
|
|
|
74,000 |
|
|
|
430,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
504,000 |
|
Total revenues
|
|
|
17,514,000 |
|
|
|
30,064,000 |
|
|
|
- |
|
|
|
18,348,000 |
|
|
|
- |
|
|
|
65,926,000 |
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
3,268,000 |
|
|
|
8,097,000 |
|
|
|
- |
|
|
|
1,478,000 |
|
|
|
13,000 |
(i) |
|
|
12,856,000 |
|
Exploration expense
|
|
|
- |
|
|
|
2,490,000 |
|
|
|
- |
|
|
|
390,000 |
|
|
|
173,000 |
(i) |
|
|
3,053,000 |
|
Production taxes
|
|
|
1,582,000 |
|
|
|
1,225,000 |
|
|
|
- |
|
|
|
855,000 |
|
|
|
- |
|
|
|
3,662,000 |
|
Workover, well service and water-disposal
|
|
|
789,000 |
|
|
|
454,000 |
|
|
|
- |
|
|
|
50,000 |
|
|
|
- |
|
|
|
1,293,000 |
|
Depreciation, depletion and amortization
|
|
|
3,881,000 |
|
|
|
17,111,000 |
|
|
|
(304,000 |
) |
|
|
2,499,000 |
(h) |
|
|
- |
|
|
|
23,187,000 |
|
Impairment expense
|
|
|
- |
|
|
|
12,298,000 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
12,298,000 |
|
General and administrative expenses
|
|
|
2,628,000 |
|
|
|
7,750,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,378,000 |
|
Accretion of asset retirement obligations
|
|
|
202,000 |
|
|
|
217,000 |
|
|
|
- |
|
|
|
10,000 |
|
|
|
- |
|
|
|
429,000 |
|
Total operating expenses
|
|
|
12,350,000 |
|
|
|
49,642,000 |
|
|
|
(304,000 |
) |
|
|
5,282,000 |
|
|
|
186,000 |
|
|
|
67,156,000 |
|
OPERATING INCOME
|
|
|
5,164,000 |
|
|
|
(19,578,000 |
) |
|
|
304,000 |
|
|
|
13,066,000 |
|
|
|
(186,000 |
) |
|
|
(1,230,000 |
) |
LOSS ON SALE OF OIL AND GAS PROPERTY
|
|
|
- |
|
|
|
(122,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(122,000 |
) |
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(173,000 |
) |
|
|
(486,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
173,000 |
(k) |
|
|
(486,000 |
) |
Derivative loss
|
|
|
- |
|
|
|
296,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
296,000 |
|
Other income
|
|
|
73,000 |
|
|
|
15,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
88,000 |
|
Total other income (expense), net
|
|
|
(100,000 |
) |
|
|
(175,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
173,000 |
|
|
|
(102,000 |
) |
INCOME BEFORE INCOME TAXES
|
|
|
5,064,000 |
|
|
|
(19,875,000 |
) |
|
|
304,000 |
|
|
|
13,066,000 |
|
|
|
(13,000 |
) |
|
|
(1,454,000 |
) |
INCOME TAX (EXPENSE) BENEFIT
|
|
|
(1,125,000 |
) |
|
|
- |
|
|
|
(112,000 |
) (m) |
|
|
(4,704,000 |
) (m) |
|
|
5,000 |
(l) |
|
|
439,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,375,000 |
(m) |
|
|
|
|
NET INCOME
|
|
$ |
3,939,000 |
|
|
$ |
(19,875,000 |
) |
|
$ |
192,000 |
|
|
$ |
8,362,000 |
|
|
$ |
6,367,000 |
|
|
$ |
(1,015,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(0.09 |
) |
Diluted
|
|
$ |
2.27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE COMMON
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHARES OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1,731,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,876,000 |
|
Diluted
|
|
|
1,731,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,876,000 |
|
The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.
Notes to the Unaudited Pro Forma Condensed Consolidated Combined Financial Statements
1. Basis of Presentation
The unaudited pro forma condensed consolidated combined balance sheet as of June 30, 2014 is based on the unaudited consolidated balance sheets of Earthstone and Oak Valley as of June 30, 2014, adjusted to reflect the following items as though they had occurred on June 30, 2014 (the “Transaction”):
●
|
The preliminary purchase accounting adjustments made based on values assigned to the Earthstone assets to be acquired and liabilities to be assumed;
|
●
|
The expected issuance of approximately 9.1 million shares of Earthstone, par value $0.001 per share, to Oak Valley in exchange for all Oak Valley’s membership interests in Oak Valley Operating, LLC, EF Non-Op, LLC and Sabine River Energy, LLC; and
|
●
|
The repayment of Earthstone’s and Oak Valley’s total debt outstanding upon closing of the Exchange.
|
The unaudited pro forma condensed consolidated combined statement of operations for the six months ended June 30, 2014 is based on Oak Valley’s unaudited consolidated statement operations for such period, and on Earthstone’s (i) audited consolidated statement of operations for the year ended March 31, 2014; less its (ii) unaudited consolidated statement of operations for the nine months ended December 31, 2013; plus its (iii) unaudited consolidated statement of operations for the three months ended June 30, 2014, with adjustments made to recast such historical operations as if the Transaction occurred on January 1, 2013.
The unaudited pro forma condensed consolidated combined statement of operations for the twelve months ended December 31, 2013 is based on Oak Valley’s audited consolidated statement operations for such period, and on Earthstone’s audited consolidated statement of operations for the year ended March 31, 2014, with adjustments made to recast such historical operations as if the Transaction occurred on January 1, 2013. Earthstone’s fiscal year end is March 31 and Oak Valley’s fiscal year end is December 31. After the Exchange, the combined company will maintain Oak Valley’s fiscal year end of December 31; however, the fiscal years are not being conformed for the purpose of presenting pro forma condensed consolidated combined financial statements, pursuant to Rule 11-02(c)(3) of
Regulation S-X, because the two fiscal year ends are not separated by more than 93 days.
The unaudited pro forma condensed consolidated combined financial statements are presented under the Successful Efforts method of accounting. Under this method, exploration activities and the cost of unsuccessful exploratory wells are expensed as incurred while under the Full Cost method, exploration activities and the cost of unsuccessful exploratory wells are capitalized. The Successful Efforts method requires that the capitalized lease acquisition costs and development costs from unsuccessful wells be amortized on a units-of-production basis at the field level based on total proved reserves and proved developed reserves, respectively. Under the Full Cost method, the capitalized costs of successful and unsuccessful exploratory and developmental wells plus the estimated future development costs on a single cost center basis per country is amortized on a unit-of-production basis against total proved reserves.
2. Pro Forma Adjustments
The following adjustments were made in the preparation of the unaudited pro forma condensed consolidated combined balance sheet and unaudited pro forma condensed consolidated combined statement of operations:
(a)
|
Adjustments to reflect the elimination of Additional Paid-In Capital, Treasury Stock, and Accumulated Earnings of Earthstone, the estimated value of consideration to be paid by the Company in the Exchange and to adjust, where required, the historical book values of Earthstone’s assets and liabilities as of June 30, 2014 to the estimated fair value, in accordance with the Acquisition method of accounting.
|
The estimated fair value of the consideration to be transferred is described below:
Number of Earthstone common shares before the Exchange
|
|
|
1,734,000 |
|
|
|
16 |
% |
Director and Officer Restricted Shares
|
|
|
18,000 |
|
|
|
0 |
% |
Number of Earthstone common shares to be issued in the Exchange
|
|
|
9,124,000 |
|
|
|
84 |
% |
Total Earthstone common shares outstanding following the Exchange
|
|
|
10,876,000 |
|
|
|
100 |
% |
Number of Earthstone common shares issued as consideration
|
|
|
1,752,000 |
|
|
|
|
|
Closing price of Earthstone common stock (1)
|
|
$ |
33.52 |
|
|
|
|
|
Total preliminary estimated purchase price
|
|
$ |
58,727,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value of Assets Acquired
|
|
|
|
|
|
|
|
|
Cash
|
|
|
2,119,000 |
|
|
|
|
|
Other current assets
|
|
|
5,440,000 |
|
|
|
|
|
Proved natural gas and oil properties
|
|
|
60,400,000 |
|
|
|
|
|
Unproved natural gas and oil properties
|
|
|
687,000 |
|
|
|
|
|
Other non-current assets
|
|
|
785,000 |
|
|
|
|
|
Total assets acquired
|
|
$ |
69,431,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Fair Value of Liabilities Assumed
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
6,011,000 |
|
|
|
|
|
Long-term debt
|
|
|
8,000,000 |
|
|
|
|
|
Deferred tax liability (2)
|
|
|
15,865,000 |
|
|
|
|
|
Asset retirement obligation
|
|
|
2,126,000 |
|
|
|
|
|
Total liabilities assumed
|
|
$ |
32,002,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
21,298,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net assets acquired
|
|
$ |
58,727,000 |
|
|
|
|
|
(1)
|
The final purchase price that will be allocated will be based on Earthstone’s actual share price at closing. The share price used for this preliminary allocation is the adjusted closing price of Earthstone common stock on June 30, 2014. The final purchase consideration may be significantly different than that used for this preliminary allocation.
|
(2)
|
Amount represents the anticipated book value to tax basis difference in oil and natural gas properties as of the acquisition date on a tax effected basis of approximately 36%.
|
(b)
|
Adjustments to reflect (i) the contractually obligated remaining capital commitments under the Exchange Agreement, of approximately $107,020,000 to be contributed by OVR’s members less the expected use of cash to repay Earthstone’s ($8,000,000) and Oak Valley’s ($10,825,000) combined long-term debt of $18,825,000 and (ii) write-off of any related unamortized debt issuance costs of Earthstone ($75,000), as of the Exchange closing date.
|
(c)
|
Adjustments to reflect the recapitalization of Oak Valley upon closing of the Exchange. OVR will be issued approximately 9,124,000 shares of common stock with a par value of $0.001 per share. Oak Valley’s existing Members’ Equity less the par value of the Earthstone Common Stock will be reclassified to Additional Paid-In Capital.
|
(d)
|
Adjustments to reflect the estimated change in long-term deferred tax liabilities for temporary differences between the historical cost basis and tax basis of Oak Valley’s assets and liabilities as the result of its change in tax status to a subchapter C corporation. A corresponding charge to earnings for Oak Valley’s change in tax status has not been reflected in the unaudited pro forma condensed consolidated combined statements of operations, as the charge is considered non-recurring.
|
(e)
|
Adjustments to reflect the accrual of approximately $1.3 million in accounting, legal, advisory fees and other expenses directly related to the Exchange that were not reflected in Earthstone’s or Oak Valley’s historical financial statements.
|
(f)
|
Adjustments to reflect the change in depreciation, depletion, amortization under the Successful Efforts method of accounting and accretion expense that would have been recorded with respect to the step-up in basis of Earthstone net assets to fair value, had the Exchange occurred on January 1, 2013.
|
(g)
|
Unless otherwise noted, adjustments represent the historical statements of revenues and direct operating expenses relating to the Eagle Ford Properties for the period from January 1, 2013 to the closing dates of the Eagle Ford Acquisition, as included elsewhere in this proxy statement.
|
(h)
|
Adjustments to reflect additional depreciation, depletion, amortization and accretion expense that would have been recorded with respect to the Eagle Ford Properties, had such acquisition occurred on January 1, 2013.
|
(i)
|
Adjustments to reflect the recording of the following historical costs previously capitalized by Earthstone under the Full Cost method of accounting, which must be expensed to conform to the Successful Efforts method applied by Oak Valley:
|
|
|
Twelve Months Ended |
|
|
Six Months
Ended
|
|
|
|
|
|
|
|
|
Delay rentals
|
|
$ |
13,000 |
|
|
$ |
27,000 |
|
Geological and geophysical costs
|
|
|
94,000 |
|
|
|
260,000 |
|
Exploratory dry hole costs and other exploration costs
|
|
|
79,000 |
|
|
|
50,000 |
|
Earthstone exploration expenses
|
|
$ |
186,000 |
|
|
$ |
337,000 |
|
(j)
|
Adjustments to eliminate the non-recurring accounting, legal, advisory fees and other expenses directly related to the Exchange that were incurred during the six month period ended June 30, 2014.
|
(k)
|
Adjustments reflect the reduction of interest expense for the repayment of Earthstone’s long-term debt outstanding upon closing of the Exchange. Oak Valley’s interest expense was not eliminated even though as part of the Exchange Oak Valley’s outstanding balance will be paid off because the Oak Valley credit facility will remain in place and available for use by post-transaction Earthstone, whereas the Earthstone credit facility will be closed in connection with the repayment of the outstanding balance.
|
(l)
|
Reflects the estimated incremental income tax (expense) benefit associated with and the pro forma adjustments assuming the combined company’s earnings had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 37%. This rate is inclusive of federal and state income taxes.
|
(m)
|
Reflects the estimated incremental tax provision associated with (i) Oak Valley’s historical results of operations and pro forma adjustments assuming Oak Valley’s earnings had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 36%; and (ii) pro forma adjustments related to Earthstone’s estimated annual effective tax rate had the Exchange occurred on January 1, 2013.
|
3. Unaudited Pro Forma Supplemental Disclosure of Oil and Natural Gas Operations
The following pro forma standardized measure of the discounted net future cash flows and changes applicable to the combined company’s proved reserves reflect the effect of income taxes. Oak Valley and the Eagle Ford Acquisition are not subject to federal and state income taxes; the pro forma effect of federal and state income taxes on the standardized measure for Oak Valley and the Eagle Ford Acquisition has been reflected in the Corporate Reorganization column. The future cash flows are discounted at 10% per year and assume continuation of existing economic conditions.
The pro forma standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the pro forma standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the combined company’s proved oil and natural gas properties.
The data presented should not be viewed as representing the expected cash flow from or current value of, existing proved reserves since the computations are based on estimates and assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.
The following table provides a pro forma rollforward of the total proved reserves for the twelve months ended December 31, 2013, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of the year, as if the Eagle Ford Acquisition and the Exchange occurred on January 1, 2013 (in BOE).
|
|
Earthstone Historical
|
|
|
Oak Valley Historical
|
|
|
Eagle Ford Acquisition
|
|
|
Pro Forma Adjusted
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
2,921,333 |
|
|
|
2,593,925 |
|
|
|
- |
|
|
|
5,515,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(47,166 |
) |
|
|
2,394,696 |
|
|
|
(629,978 |
) |
|
|
1,717,552 |
|
Extensions and discoveries
|
|
|
454,333 |
|
|
|
4,812,060 |
|
|
|
817,369 |
|
|
|
6,083,762 |
|
Sales of reserves in place
|
|
|
- |
|
|
|
(14,589 |
) |
|
|
- |
|
|
|
(14,589 |
) |
Purchase of reserves
|
|
|
- |
|
|
|
2,382,771 |
|
|
|
- |
|
|
|
2,382,771 |
|
Production
|
|
|
(205,667 |
) |
|
|
(736,759 |
) |
|
|
(187,391 |
) |
|
|
(1,129,817 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
3,122,833 |
|
|
|
11,432,104 |
|
|
|
- |
|
|
|
14,554,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
1,585,000 |
|
|
|
1,938,869 |
|
|
|
- |
|
|
|
3,523,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
1,821,500 |
|
|
|
3,706,132 |
|
|
|
- |
|
|
|
5,527,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
1,336,333 |
|
|
|
655,056 |
|
|
|
- |
|
|
|
1,991,389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
1,301,333 |
|
|
|
7,725,972 |
|
|
|
- |
|
|
|
9,027,305 |
|
The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2013:
|
|
Earthstone Historical
|
|
|
Oak Valley Historical
|
|
|
Corporate Reorganization
|
|
|
Pro Forma Adjusted
|
|
Future cash inflows
|
|
$ |
246,908,000 |
|
|
$ |
718,049,000 |
|
|
$ |
- |
|
|
$ |
964,957,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash outflows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost
|
|
|
(91,392,000 |
) |
|
|
(202,957,000 |
) |
|
|
- |
|
|
|
(294,349,000 |
) |
Development cost
|
|
|
(25,563,000 |
) |
|
|
(220,829,000 |
) |
|
|
- |
|
|
|
(246,392,000 |
) |
Future income taxes
|
|
|
(28,829,000 |
) |
|
|
- |
|
|
|
(58,879,000 |
) |
|
|
(87,708,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
101,124,000 |
|
|
|
294,263,000 |
|
|
|
(58,879,000 |
) |
|
|
336,508,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment to discount future annual net cash flows at 10%
|
|
|
(52,069,000 |
) |
|
|
(168,906,000 |
) |
|
|
33,662,000 |
|
|
|
(187,313,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
49,055,000 |
|
|
$ |
125,357,000 |
|
|
$ |
(25,217,000 |
) |
|
$ |
149,195,000 |
|
The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the twelve months ended December 31, 2013:
|
|
Earthstone Historical
|
|
|
Oak Valley Historical
|
|
|
Eagle Ford Acquisition
|
|
|
Corporate Reorganization
|
|
|
Pro Forma Adjusted
|
|
|
|
Historical
|
|
|
Historical
|
|
|
Acquistion
|
|
|
Reorganization
|
|
|
Adjusted
|
|
Standardized measure, beginning of period
|
|
$ |
31,616,000 |
|
|
$ |
25,132,000 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
56,748,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas, net of production cost
|
|
|
(11,901,000 |
) |
|
|
(20,288,000 |
) |
|
|
(15,965,000 |
) |
|
|
- |
|
|
|
(48,154,000 |
) |
Net change in sales prices, net of production cost
|
|
|
10,126,000 |
|
|
|
241,000 |
|
|
|
(3,230,000 |
) |
|
|
- |
|
|
|
7,137,000 |
|
Discoveries, extensions and improved recoveries
|
|
|
6,021,000 |
|
|
|
48,006,000 |
|
|
|
9,062,000 |
|
|
|
- |
|
|
|
63,089,000 |
|
Change in future development costs
|
|
|
- |
|
|
|
(22,966,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
(22,966,000 |
) |
Development costs incurred during the period that reduced future development cost
|
|
|
9,955,000 |
|
|
|
3,227,000 |
|
|
|
10,950,000 |
|
|
|
- |
|
|
|
24,132,000 |
|
Sales of reserves in place
|
|
|
- |
|
|
|
(380,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
(380,000 |
) |
Revisions of quantity estimates
|
|
|
(1,487,000 |
) |
|
|
26,259,000 |
|
|
|
(2,688,000 |
) |
|
|
- |
|
|
|
22,084,000 |
|
Accretion of discount
|
|
|
5,729,000 |
|
|
|
2,513,000 |
|
|
|
5,695,000 |
|
|
|
- |
|
|
|
13,937,000 |
|
Net change in income taxes
|
|
|
(941,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
(25,217,000 |
) |
|
|
(26,158,000 |
) |
Purchase of reserves
|
|
|
- |
|
|
|
56,069,000 |
|
|
|
- |
|
|
|
- |
|
|
|
56,069,000 |
|
Changes in timing of rates of production
|
|
|
(63,000 |
) |
|
|
7,544,000 |
|
|
|
(3,824,000 |
) |
|
|
- |
|
|
|
3,657,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of period
|
|
$ |
49,055,000 |
|
|
$ |
125,357,000 |
|
|
$ |
- |
|
|
$ |
(25,217,000 |
) |
|
$ |
149,195,000 |
|
FINANCIAL STATEMENTS OF OAK VALLEY RESOURCES, LLC
INDEPENDENT AUDITOR’S REPORT
To the Members of
Houston, Texas
We have audited the accompanying consolidated financial statements of Oak Valley Resources, LLC and Subsidiaries (collectively, the Company), which comprise the consolidated balance sheets as of December 31, 2013, 2012, and 2011 and the related consolidated statements of operations, members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal controls relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform our audits to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oak Valley Resources, LLC and Subsidiaries as of December 31, 2013, 2012, and 2011 and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Principles of Consolidation – Business Combination under Common Control
As described in Note 2, Summary of Significant Accounting Policies, the Company’s 2012 and 2011 consolidated financial statements have been restated to give retroactive effect to a transaction accounted for as a business combination of entities under common control.
Supplementary Information – Oil and Gas Producing Activities
Our audits were conducted for the purpose of forming an opinion on the consolidated financial statements of Oak Valley Resources, LLC and Subsidiaries. The disclosures about oil and gas producing activities in Note 11 are presented for additional analysis and are not a required part of the consolidated financial statements.
The disclosures about oil and gas producing activities have not been subject to the auditing procedures applied in the audits of the consolidated financial statements of Oak Valley Resources, LLC and Subsidiaries, and accordingly, we do not express an opinion or provide any assurance on it.
Supplementary Information – Eagle Ford Acquisition pro forma Consolidated Results
Our audits were conducted for the purpose of forming an opinion on the consolidated financial statements of Oak Valley Resources, LLC and Subsidiaries. The disclosures about the Eagle Ford Acquisition pro forma consolidated results included in the Company’s historical financial information in Note 3 are presented for additional analysis and are not a required part of the consolidated financial statements.
The disclosures about the Eagle Ford Acquisition pro forma consolidated results have not been subject to the auditing procedures applied in the audits of the consolidated financial statements of Oak Valley Resources, LLC and Subsidiaries, and accordingly, we do not express an opinion or provide any assurance on it.
Houston, Texas
CONSOLIDATED BALANCE SHEETS
ASSETS
|
|
December 31,
|
|
Current assets:
|
|
2013
|
|
|
2012
|
|
Cash
|
|
$ |
25,422,741 |
|
|
$ |
20,151,399 |
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids revenues
|
|
|
8,121,930 |
|
|
|
2,635,681 |
|
Joint interest billings and other
|
|
|
7,541,245 |
|
|
|
886,648 |
|
Prepaid expenses and other assets
|
|
|
122,104 |
|
|
|
54,027 |
|
Current derivative assets
|
|
|
154,310 |
|
|
|
- |
|
|
|
|
41,362,330 |
|
|
|
23,727,755 |
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, successful efforts method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
184,075,412 |
|
|
|
110,603,202 |
|
Unproved properties
|
|
|
43,010,521 |
|
|
|
16,510,080 |
|
Total oil and gas properties
|
|
|
227,085,933 |
|
|
|
127,113,282 |
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion, and amortization
|
|
|
(79,788,805 |
) |
|
|
(63,651,474 |
) |
Net oil and gas properties
|
|
|
147,297,128 |
|
|
|
63,461,808 |
|
|
|
|
|
|
|
|
|
|
Noncurrent assets:
|
|
|
|
|
|
|
|
|
Office and other equipment, less accumulated depreciation of $191,088 and $24,900, respectively
|
|
|
560,477 |
|
|
|
149,538 |
|
Other noncurrent assets
|
|
|
537,752 |
|
|
|
202,647 |
|
Land
|
|
|
100,637 |
|
|
|
- |
|
TOTAL ASSETS
|
|
$ |
189,858,324 |
|
|
$ |
87,541,748 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS' EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
7,428,304 |
|
|
$ |
3,324,496 |
|
Accrued expenses
|
|
|
5,768,144 |
|
|
|
7,701,220 |
|
Revenues and royalties payable
|
|
|
10,184,145 |
|
|
|
486,115 |
|
Advances
|
|
|
3,519,881 |
|
|
|
- |
|
Current derivative liabilities
|
|
|
171,761 |
|
|
|
- |
|
Asset retirement obligations
|
|
|
69,956 |
|
|
|
- |
|
Total current liabilities
|
|
|
27,142,191 |
|
|
|
11,511,831 |
|
|
|
|
|
|
|
|
|
|
Noncurrent liabilities:
|
|
|
|
|
|
|
|
|
Noncurrent derivative liabilities
|
|
|
27,816 |
|
|
|
- |
|
Long-term debt
|
|
|
10,825,000 |
|
|
|
10,825,000 |
|
Asset retirement obligations
|
|
|
2,941,498 |
|
|
|
3,937,743 |
|
Total noncurrent liabilities
|
|
|
13,794,314 |
|
|
|
14,762,743 |
|
|
|
|
|
|
|
|
|
|
|
|
|
40,936,505 |
|
|
|
26,274,574 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Members' equity
|
|
|
148,921,819 |
|
|
|
61,267,174 |
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND MEMBERS' EQUITY
|
|
$ |
189,858,324 |
|
|
$ |
87,541,748 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
Year Ended December 31,
|
|
REVENUES
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
Oil, natural gas, and natural gas liquids revenues:
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$ |
16,037,861 |
|
|
$ |
8,679,346 |
|
|
$ |
6,517,806 |
|
Natural gas
|
|
|
9,714,171 |
|
|
|
6,064,065 |
|
|
|
12,054,176 |
|
Natural gas liquids
|
|
|
3,881,876 |
|
|
|
2,348,169 |
|
|
|
1,653,405 |
|
Total oil, natural gas, and natural gas liquids revenues
|
|
|
29,633,908 |
|
|
|
17,091,580 |
|
|
|
20,225,387 |
|
Gathering income
|
|
|
430,275 |
|
|
|
418,942 |
|
|
|
600,250 |
|
Gain (loss) on sale of oil and gas properties
|
|
|
(121,519 |
) |
|
|
4,784,504 |
|
|
|
(5,355,679 |
) |
Total revenues
|
|
|
29,942,664 |
|
|
|
22,295,026 |
|
|
|
15,469,958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
8,425,987 |
|
|
|
6,211,275 |
|
|
|
7,459,628 |
|
Severance taxes
|
|
|
1,225,313 |
|
|
|
608,065 |
|
|
|
835,346 |
|
Re-engineering and workovers
|
|
|
342,254 |
|
|
|
569,579 |
|
|
|
717,523 |
|
Depreciation, depletion, and amortization
|
|
|
17,110,930 |
|
|
|
12,190,821 |
|
|
|
16,235,811 |
|
Impairment expense
|
|
|
12,297,681 |
|
|
|
52,474,953 |
|
|
|
34,294,188 |
|
Exploration expense
|
|
|
2,490,176 |
|
|
|
57,444 |
|
|
|
11,185 |
|
General and administrative expense
|
|
|
7,750,497 |
|
|
|
3,280,254 |
|
|
|
3,141,990 |
|
Total operating expenses
|
|
|
49,642,838 |
|
|
|
75,392,391 |
|
|
|
62,695,671 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(19,700,174 |
) |
|
|
(53,097,365 |
) |
|
|
(47,225,713 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSES)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(487,330 |
) |
|
|
(279,872 |
) |
|
|
(231,454 |
) |
|
|
|
296,269 |
|
|
|
- |
|
|
|
- |
|
Interest income
|
|
|
1,065 |
|
|
|
7,523 |
|
|
|
5,470 |
|
Other income (expenses), net
|
|
|
14,815 |
|
|
|
48,871 |
|
|
|
661,043 |
|
Total other income (expenses)
|
|
|
(175,181 |
) |
|
|
(223,478 |
) |
|
|
435,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS
|
|
$ |
(19,875,355 |
) |
|
$ |
(53,320,843 |
) |
|
$ |
(46,790,654 |
) |
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
|
|
Members' Equity
|
|
|
|
|
|
|
|
$ |
124,510,028 |
|
|
|
|
|
|
Net loss
|
|
|
(46,790,654 |
) |
|
|
|
|
|
Members' equity contributions, net of issuance costs of $209,900
|
|
|
13,685,899 |
|
|
|
|
|
|
Members' equity distributions
|
|
|
(420,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
90,985,273 |
|
|
|
|
|
|
Net loss
|
|
|
(53,320,843 |
) |
|
|
|
|
|
Members' equity contributions, net of issuance costs of $499,501
|
|
|
24,790,167 |
|
|
|
|
|
|
Members' equity distributions
|
|
|
(1,187,423 |
) |
|
|
|
|
|
|
|
$ |
61,267,174 |
|
|
|
|
|
|
Net loss
|
|
|
(19,875,355 |
) |
|
|
|
|
|
Members' equity contributions, net of issuance costs of $791,837
|
|
|
107,530,000 |
|
|
|
|
|
|
|
|
$ |
148,921,819 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$ |
(19,875,355 |
) |
|
$ |
(53,320,843 |
) |
|
$ |
(46,790,654 |
) |
Adjustments to reconcile net loss to net cash provided
|
|
|
|
|
|
|
|
|
|
|
|
|
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
17,110,930 |
|
|
|
12,190,821 |
|
|
|
16,235,811 |
|
Impairment of proved and unproved oil and gas properties
|
|
|
12,297,681 |
|
|
|
52,474,953 |
|
|
|
34,294,188 |
|
Dry hole costs
|
|
|
2,095,748 |
|
|
|
57,444 |
|
|
|
11,185 |
|
(Gain) loss on sales of oil and gas properties
|
|
|
121,519 |
|
|
|
(4,784,504 |
) |
|
|
5,355,679 |
|
Accretion of asset retirement obligations
|
|
|
216,599 |
|
|
|
178,802 |
|
|
|
174,671 |
|
|
|
|
45,267 |
|
|
|
- |
|
|
|
- |
|
Amortization of deferred financing costs
|
|
|
103,513 |
|
|
|
47,811 |
|
|
|
31,288 |
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable
|
|
|
(12,140,846 |
) |
|
|
1,201,865 |
|
|
|
(739,453 |
) |
Decrease (increase) in prepaid expense and other
|
|
|
(81,806 |
) |
|
|
88,534 |
|
|
|
(71,841 |
) |
Increase in accounts payable and accrued expenses
|
|
|
2,170,732 |
|
|
|
6,761,995 |
|
|
|
1,395,505 |
|
Increase in revenue and royalties payable
|
|
|
9,698,030 |
|
|
|
88,120 |
|
|
|
265,254 |
|
Increase in advances
|
|
|
3,519,881 |
|
|
|
- |
|
|
|
- |
|
Net cash provided by operating activities
|
|
|
15,281,893 |
|
|
|
14,984,998 |
|
|
|
10,161,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of proved and unproved property
|
|
|
(86,686,606 |
) |
|
|
- |
|
|
|
- |
|
Additions to oil and gas property and equipment
|
|
|
(31,162,231 |
) |
|
|
(39,432,668 |
) |
|
|
(21,505,859 |
) |
Additions to other property and equipment
|
|
|
(677,765 |
) |
|
|
(97,315 |
) |
|
|
(77,123 |
) |
Insurance proceeds
|
|
|
922,978 |
|
|
|
- |
|
|
|
- |
|
Proceeds from sales of oil and gas properties
|
|
|
487,963 |
|
|
|
9,976,369 |
|
|
|
2,137,293 |
|
Net cash used in investing activities
|
|
|
(117,115,661 |
) |
|
|
(29,553,614 |
) |
|
|
(19,445,689 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of long-term debt
|
|
|
- |
|
|
|
10,825,000 |
|
|
|
42,115 |
|
Reduction of long-term debt
|
|
|
- |
|
|
|
(5,192,115 |
) |
|
|
(1,350,000 |
) |
Deferred financing costs
|
|
|
(424,890 |
) |
|
|
(19,693 |
) |
|
|
(262,053 |
) |
Contributions, net of issuance costs of $791,837, $499,501, and $209,900, respectively
|
|
|
107,530,000 |
|
|
|
24,790,167 |
|
|
|
13,685,899 |
|
Distributions
|
|
|
- |
|
|
|
(1,187,423 |
) |
|
|
- |
|
|
|
|
- |
|
|
|
- |
|
|
|
(420,000 |
) |
Net cash provided by financing activities
|
|
|
107,105,110 |
|
|
|
29,215,936 |
|
|
|
11,695,961 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
5,271,342 |
|
|
|
14,647,320 |
|
|
|
2,411,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, at beginning of period
|
|
|
20,151,399 |
|
|
|
5,504,079 |
|
|
|
3,092,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, at end of period
|
|
$ |
25,422,741 |
|
|
$ |
20,151,399 |
|
|
$ |
5,504,079 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS – CONTINUED
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$ |
375,036 |
|
|
$ |
238,281 |
|
|
$ |
158,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Disclosure of non-cash investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$ |
1,033,246 |
|
|
$ |
66,191 |
|
|
$ |
388,126 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND BUSINESS
Oak Valley Resources, LLC (“OVR” or the “Company”), is a Delaware limited liability company formed on December 14, 2012. OVR is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (“NGL”). The Company currently has properties in Texas, Oklahoma, and Louisiana.
On December 21, 2012, the Company was capitalized by affiliates of EnCap Investments L.P. (“EnCap”) via the contribution of certain oil and gas properties (the “Contributed Properties”), which were conveyed by assigning 100% of the issued and outstanding membership interests in ECC VI, LLC (“ECC VI”) and 100% of the issued and outstanding membership interest in Oak Valley Energy, LLC (“OVE”) in exchange for Class A Membership Interests (“Class A Units”) of the Company.
On December 21, 2012, in addition to the conveyance of the Contributed Properties, EnCap, Wells Fargo Central Pacific Holdings, Inc. (“Wells Fargo”), and VILLco Capital II, L.L.C. (“VILLco”), committed an aggregate of $145,000,000 in exchange for future Class A Units. Also, on December 21, 2012, Oak Valley Management, LLC (“OVM”), whose members are management and employees of the Company, committed $5,000,000 in exchange for future Class B Membership Interests (“Class B Units”). During 2013, additional members were admitted to OVM, with capital commitments totaling $1,730,000. As of December 31, 2013 OVM’s capital commitment to OVR totaled $6,730,000. EnCap, Wells Fargo,
VILLco, and OVM are collectively referred to herein as “Round I Investors”.
On April 25, 2013, the Company closed a private placement offering amongst accredited investors (“Private Placement Investors”, and together with Round 1 Investors and OVM, “Investors”) that raised $62,820,000 in capital commitments in exchange for future Class A Units. Similar to EnCap, Wells Fargo, and VILLco, Private Placement Investors will receive future Class A units valued at $100.00 per unit.
Based on the value of the Contributed Properties and the amount of capital commitments received, equity ownership in the Company consists of EnCap with 57.2%, Private Placement Investors with 23.5%, Wells Fargo with 9.3%, VILLco with 7.5%, and OVM with 2.5%.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Prior to being capitalized on December 21, 2012, all of the Company’s wholly owned subsidiaries were controlled by EnCap. All of the companies included in the transaction had fiscal years ending December 31. The consolidated financial statements for the periods ended December 31, 2012 and 2011 were prepared by combining all the previously separate subsidiaries in accordance
with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC Topic 805”). ASC Topic 805 states that if a transaction combines two or more commonly controlled entities that historically have not been presented together, the resulting financial statements for those periods presented require retrospective presentation of the financial statements for all the periods presented, as if the combination had been in effect since the inception of common control.
When accounting for a transfer of assets or exchange of equity interests between entities under common control, the entity that receives the net assets or the equity interests should initially measure the assets and liabilities transferred at their historical carrying amounts. Therefore, the net assets included in the accompanying consolidated financial statements are shown at their historical carrying value.
On December 18, 2012, prior to the assignment of OVE membership interests to the Company, one of OVE’s subsidiaries was transferred to a non-affiliated entity. In accordance with ASC Topic 805, the consolidated financial statements include the activities of that subsidiary through the date of transfer. The amount of revenue and net income from the OVE subsidiary included in the Company’s Consolidated Statement of Operations for the year ended December 31, 2012, was $4,233,613 and $2,435,030, respectively. The amount of revenue and net loss from the OVE subsidiary included
in the Company’s Consolidated Statement of Operations for the year ended December 31, 2011, was $2,466,779 and $175,519, respectively. Please see Note 3 “Acquisitions and Divestitures” for more information on this transfer.
Certain reclassifications between “Oil, natural gas, and natural gas liquids revenues”, and “Accrued expenses” were made to the year ended December 31, 2012 Consolidated Balance Sheet. The Company also reclassified amounts between “Oil”, and “Natural gas liquids” on the December 31, 2012 Consolidated Statement of Operations. Finally, the Company reclassified amounts between “Accounts receivable”, which is included in the “Cash flows from operating activities”, and “Proceeds from sales of oil and gas properties”,
which is included in the “Cash flows from investing activities”, on the December 31, 2011 Consolidated Statement of Cash Flows.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Principles of Consolidation – Continued
All reclassifications were made to conform to the current year presentation. Such reclassifications had no impact on net income, working capital, or members’ equity previously reported.
|
● |
Oak Valley Energy, LLC (“OVE”), is a Delaware limited liability company formed on December 7, 2010. As of December 31, 2013, OVE’s wholly owned subsidiaries included: |
|
|
|
|
● |
Oak Valley Operating, LLC (“OVO”), a Texas limited liability company formed on May 26, 2011. OVO serves as the operator on all Company-operated properties; |
|
|
|
|
● |
Destiny Oil & Gas, LLC (“Destiny”), a Delaware limited liability company formed on June 13, 2006, which held interests in oil and gas properties located in Louisiana; |
|
|
|
|
● |
EF Non-op, LLC, a Texas limited liability company formed on December 1, 2010, that holds interests in oil and gas properties located in Texas; |
|
|
|
|
● |
Paladar Investments I, L.L.C, (“Paladar”) a Texas limited liability company formed on August 13, 2007, which held interests in oil and gas properties located in Texas; |
|
|
|
|
● |
Sabine River Energy, LLC (“Sabine”), a Texas limited liability company formed on May 18, 2011, which holds interests in oil and gas properties located in Texas and Louisiana. |
|
|
|
|
● |
ECC VI, LLC (“ECC VI”), is a Delaware limited liability company formed on December 9, 2010. As of December 31, 2013, ECC VI’s wholly-owned subsidiaries included: |
|
|
|
|
● |
ECCVI East Texas, LLC (“ECCVI East Texas”), a Texas limited liability company formed on December 9, 2010, which held interests in oil and gas properties located in Texas. |
|
|
|
|
● |
ECC VI Oklahoma, LLC (“ECC VI Oklahoma”), a Delaware limited liability company formed on September 1, 2011, which held interests in oil and gas properties located in Oklahoma. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Principles of Consolidation – Continued
Effective December 31, 2013, the Company dissolved OVE, Destiny, Paladar, ECC VI, ECCVI East Texas, and ECC VI Oklahoma, (“the Dissolved Subsidiaries”) to simplify its organizational structure. Prior to dissolving OVE, OVE’s membership interest in OVO, EF Non-op, and Sabine were assigned to OVR. During 2013, properties held by Destiny, Paladar, ECCVI East Texas, and ECC VI Oklahoma were assigned to Sabine. The results of operations for the Dissolved Subsidiaries have been included in the consolidated financial statements through December 31, 2013.
The long-term debt of OVR, under its Credit Agreement discussed in Note 7 “Long-term Debt”, is fully and unconditionally guaranteed by all of its subsidiaries, all of which are wholly owned.
All intercompany accounts and transactions are eliminated in consolidation.
Subsequent Events
Management has evaluated subsequent events for the Company through July 1, 2014, the date upon which these consolidated financial statements were available to be issued. Please see Note 12 “Subsequent Events” for the results of that evaluation.
Use of Estimates
The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of the Company’s management, are significant include oil and natural gas reserves and the related cash flow estimates used in depletion and impairment of oil and
natural gas properties, the evaluation of unproved properties for impairment, fair value estimates, asset retirement obligations, oil and natural gas revenue accruals, lease operating expense accruals, and capital accruals. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the
Company’s consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Cash
Cash consists of cash on deposit.
Accounts Receivable
Accounts receivable include amounts due from oil, natural gas, and NGL purchasers, other operators for which the Company holds an interest, and from non-operating working interest owners. Accrued oil, natural gas, and NGL sales from purchasers and operators consist of accrued revenues due under normal trade terms, generally requiring payment within 60 days of production.
An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectible are charged to the allowance.
Provisions for bad debts and recoveries on accounts previously charged off are added to the allowance. The Company routinely assesses the recoverability of all material trade receivables and other receivables to determine their collectability. At December 31, 2013, 2012, and 2011, the Company did not have an allowance for doubtful accounts as all accounts receivable were deemed collectible by management.
Derivative Instruments
The Company utilizes derivative instruments in order to manage exposure to commodity price risk associated with future crude oil and natural gas production. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated values of derivative contracts
held at the balance sheet date are recognized in the Consolidated Statement of Operations as unrealized gains or losses on derivative contracts.
Proved Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and gas properties. Costs incurred by the Company related to the acquisition of oil and gas properties and the cost of drilling development wells and successful exploratory wells are capitalized. Exploration costs, including unsuccessful exploratory wells and geological and geophysical costs, are charged to operations as incurred. Upon sale of oil and gas properties, the costs and related accumulated depreciation, depletion, and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Proved Oil and Gas Properties – Continued
amortization are eliminated from the accounts and the resulting gain or loss is recognized.
Costs incurred to maintain wells and related equipment, lease and well operating costs, and other exploration costs are charged to expense as incurred. Additions to proved oil and gas properties that are accrued at year-end are included in “Additions to oil and gas property and equipment” on the Consolidated Statements of Cash Flows, if the additions will be paid within twelve months of year-end. Gains and losses arising from the sale of properties are included in operating income.
The Company’s lease acquisition costs and development costs of proved oil and gas properties are amortized using the units-of-production method, at the field level, based on total proved reserves and proved developed reserves, respectively. Depletion expense for oil and gas producing property and related equipment was $16,944,741, $12,172,643, and $16,229,089, for the years ended December 31, 2013, 2012, and 2011, respectively.
Proved oil and gas properties are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the expected future cash flow expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to its estimated fair value.
Each component of an impairment calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, estimated future net cash flows, and fair value. The Company recognized impairments of $9,817,182, $43,907,927, and $15,400,191 for the years ended December 31, 2013, 2012, and 2011, respectively, on proved oil and gas properties.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire undeveloped leases as well as the cost to acquire unproved reserves. Undeveloped lease costs and unproved reserve acquisition costs are capitalized. If additions to unproved oil and gas properties will be paid within twelve months of year-end, then such additions are accrued for at year-end and are included in the “Additions to oil and gas property and equipment” financial statement line item on the Consolidated Statements of Cash Flows. Unproved oil and gas leases are generally for a primary term of three to five years. In most cases, the term of the unproved leases can be extended by paying delay rentals, meeting contractual drilling obligations, or by the presence of producing wells on the leases. Unproved costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Unproved Oil and Gas Properties – Continued
Unproved properties are assessed periodically to determine whether they have been impaired based on remaining lease term, drilling results, reservoir performance, seismic interpretation, or future plans to develop acreage.
The Company recognized impairments of $2,480,499, $8,567,026, and $18,893,997 for the years ended December 31, 2013, 2012, and 2011, respectively, on unproved oil and gas properties.
Asset Retirement Obligations
Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon, remediate oil and gas wells, remove equipment and facilities from leased acreage, and return land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the producing location), and the costs of such liability increases the carrying amount of the related long-lived asset by the same amount.
After the liability is initially recorded, the carrying amount of the related long-lived asset is increased over time through a charge to accretion expense each period and the capitalized cost is depleted on a units-of-production basis based on the proved developed reserves of the related assets. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability. See Note 8 “Asset Retirement Obligations” for further disclosure regarding the asset retirement obligation.
Business Combinations
The Company accounts for the acquisition of oil and gas properties, that are not commonly controlled, based on the requirements of ASC Topic 805, which requires an acquiring entity to recognize the assets acquired and liabilities assumed at fair value under the acquisition method of accounting, provided such assets and liabilities qualify for acquisition accounting under the standard. The Company accounts for property acquisitions of proved oil and gas property as business combinations.
Revenue Recognition
Oil, natural gas, and NGL revenues represent income from production and delivery of oil, natural gas, and NGL, recorded net of royalties. Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has been transferred, and collectability of the revenue is probable. The Company follows the sales method of accounting for gas imbalances. The Company had no significant gas imbalances as of December 31, 2013, 2012, or 2011.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Concentration of Credit Risk
Credit risk represents the actual or perceived financial loss that the Company would record if its purchasers, operators, or counterparties failed to perform pursuant to contractual terms.
The purchasers of the Company’s oil, natural gas, and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. In 2013, one purchaser accounted for 21% of the Company’s oil, natural gas, and NGL revenues. No other purchaser accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2013, 2012, and 2011.
The Company holds working interests in oil and gas properties for which a third party serves as operator. The operator sells the crude oil, natural gas, and NGL to the purchaser, collects the cash, and distributes the cash to the Company. The Company recognizes the cash received as revenue. In 2013, two operators distributed 47% and 11% of the Company’s oil, natural gas, and NGL revenues, respectively. In 2012, two operators distributed 65% and 18% of the Company’s oil, natural gas, and NGL revenues, respectively.
In 2011, two operators distributed 25% and 33% of the Company’s oil, natural gas, and NGL revenues respectively. No other operator accounted for 10% or more of the Company’s oil, natural gas, and NGL revenues during 2013, 2012, and 2011.
If purchasers and operators fail to perform pursuant to contractual terms, then the Company’s overall business may be adversely impacted. The Company’s management believes this risk is mitigated by the size, and reputation, of its purchasers and operators.
Commodity derivative contracts held by the Company are with two counterparties. Both counterparties are participants in the Company’s credit facility and possess investment-grade ratings from Moody’s and Standard & Poor.
The Company regularly maintains its cash in bank deposit accounts. Balances held by the Company at its bank typically exceed Federal Deposit Insurance Corporation (“FDIC”) insurance coverage, and as a result, there is a concentration of credit risk related to the amounts of deposit in excess of FDIC insurance coverage. The Company’s management believes this risk is not significant based upon the size and reputation of the financial institutions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Income Taxes
The Company is organized as a Delaware limited liability company and is treated as a flow-through entity for income tax purposes. As a result, the net taxable income of the Company and any related tax credits, for federal income tax purposes, are deemed to pass to the members of the Company even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no federal income tax provision has been made in the consolidated financial statements of the Company since the federal income tax is an obligation of the members.
The State of Texas has a margin tax which taxes companies for the “privilege” of doing business in Texas. As a part of its privilege, the members of the Company receive liability protections under state law. The Company has not recorded a provision for the tax at December 31, 2013, 2012, or 2011, as management does not believe the amount owed, if any, will be material to the Company.
The Company follows the provisions of FASB ASC Topic 740, Income Taxes (“ASC Topic 740”), relating to accounting for uncertainties in income taxes. ASC Topic 740 clarifies the accounting for uncertainties in income taxes by prescribing a minimum recognition threshold that a tax position is required to meet before being recognized in the consolidated financial statements. ASC Topic 740 requires that the Company recognize in the consolidated financial statements the financial effects of a tax position, if that position is more likely than not of being sustained upon examination, including resolution of any appeals or litigation processes, based upon the technical merits of the position. ASC Topic 740 also provides guidance on measurement,
classification, interest and penalties and disclosure. Tax positions taken related to the Company’s pass-through status and state income tax liability, including deductibility of expenses, have been reviewed and the Company’s management is of the opinion that material positions taken by the Company would more likely than not be sustained upon examination. Accordingly, the Company has not recorded an income tax liability for uncertain tax positions at December 31, 2013, 2012, or 2011. The 2010 through 2013 tax years generally remain subject to
examination.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES – CONTINUED
Recently Issued Accounting Pronouncements
In December 2011, FASB issued Accounting Standards Update (“ASU”) No. 2011-11, Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which enhances disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of its financial statements to understand the effect of those arrangements on its financial position. This pronouncement was issued to facilitate comparison between financial statements prepared on the basis of accounting principles generally accepted in the United States and International Financial Reporting Standards. In addition, in January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”), which requires clarification of the specific instruments that should be considered in the offsetting
disclosures. These updates are effective for annual and interim reporting periods beginning on or after January 1, 2013 and are to be applied retroactively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 resulted in new disclosures related to the Company’s derivative activities. See further information at Note 4, “Derivative Financial Instruments.”
NOTE 3. ACQUISTIONS AND DIVESTITURES
Eagle Ford Acquisition
In July 2013 and August 2013, the Company purchased producing wells and acreage in the Eagle Ford shale trend of Texas for approximately $71,632,740 and $15,053,866, respectively (the “Eagle Ford Acquisition”). Acquisition costs of $1,063,966 are included in “General and administrative expense” in the Consolidated Statement of Operations. The acquisition expanded the Company’s presence in the Eagle Ford, adding oil and natural gas reserves and production to its existing asset base in this area.
The Eagle Ford Acquisition was accounted for as a business combination in accordance with ASC Topic 805, which among other things, requires assets acquired and liabilities assumed to be measured at fair value as of the effective date of the acquisition. The effective date of the Eagle Ford Acquisition was January 1, 2013. The estimated fair value of the properties approximates the fair value of consideration, and as a result, no goodwill was recognized.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3. ACQUISTIONS AND DIVESTITURES – CONTINUED
Eagle Ford Acquisition – Continued
The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of the acquisition date. The purchase price of $71,632,740 and $15,053,866 are subject to closing adjustments for normal operational activity and other purchase price adjustments that occur between the effective date of the acquisition and the closing date of the acquisition. As the purchase price is further adjusted for post-closing items, the final purchase price allocation may result in a different allocation:
|
|
|
|
Purchase price
|
|
$ |
86,686,606 |
|
Allocation of purchase price:
|
|
|
|
|
Proved properties |
|
$ |
57,254,842 |
|
Unproved properties |
|
|
30,041,094 |
|
Asset retirement obligations |
|
|
(609,330 |
) |
Total |
|
$ |
86,686,606 |
|
|
|
|
|
|
The amount of revenue and net income from the Eagle Ford Acquisition included in the Company’s Consolidated Statement of Operations for the year ended December 31, 2013, was $9,514,139 and $6,245,285, respectively.
The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2013 and 2012 as if the Eagle Ford Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2012. The pro forma combined results of operations for the years ended December 31, 2013 and 2012 have been prepared by adjusting historical results of the Company to include the historical results of the Eagle Ford Acquisition. These supplemental pro-forma results of operations are provided for illustrative purposes only and
do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Eagle Ford Acquisition or any estimated costs that will be incurred to integrate the Eagle Ford Acquisition. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3. ACQUISTIONS AND DIVESTITURES – CONTINUED
Eagle Ford Acquisition – Continued
The unaudited pro forma consolidated results include the Company’s historical financial information and the revenues and expenses of assets acquired and liabilities assumed in the Eagle Ford Acquisition.
|
|
|
|
|
|
|
|
|
2012
|
|
Revenue
|
|
$ |
48,290,527 |
|
|
$ |
39,803,888 |
|
Net Loss
|
|
$ |
(5,240,297 |
) |
|
$ |
(39,796,323 |
) |
2013 Divestitures
On May 17, 2013, the Company sold undeveloped acreage and working interest in nine wells located in Guadalupe County, Texas, and Caldwell County, Texas for cash consideration of $487,863. The Company recorded a loss on sale of $54,433. The effective date of the sale was April 1, 2013.
On March 28, 2013, the Company sold undeveloped acreage in Harrison County, Texas, and the working interest in one well for cash consideration of $100. The Company recorded a loss on sale of $67,086. The effective date of the sale was April 1, 2013.
2012 Acquisitions and Divestitures
On December 18, 2012, OVE assigned all of the membership interests of one of its wholly owned subsidiaries (the “Assigned Subsidiary”) to an entity unaffiliated with OVE and OVR. The consolidated financial statements include the accounts of the Assigned Subsidiary through the date of assignment. Prior to the assignment, in February 2012, the Company closed on a sale of all of the oil and natural gas assets of the Assigned Subsidiary for cash consideration of $8,455,760. The Company used $5,192,115 of the proceeds to pay down the credit facility and the remainder to fund capital expenditures and for general corporate
purposes. The Company recorded a $4,081,184 gain on the sale.
On April 4, 2012, the Company acquired various working interests in certain wells and undeveloped acreage in Caddo and DeSoto Parishes, Louisiana, for cash consideration of $1,555,779. The Company acquired working interests in 19 wells, including additional interests in eight wells operated by OVO. The effective date of the acquisition was January 1, 2012.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3. ACQUISTIONS AND DIVESTITURES – CONTINUED
2012 Acquisitions and Divestitures – Continued
On March 8, 2012, the Company sold working interests and unitized producing acreage in two wells in Lincoln and Webster Parishes, Louisiana, for cash consideration of $55,609. The Company recorded a gain on sale of $55,451. The effective date of the sale was January 1, 2012.
On March 8, 2012, the Company sold working interests in six wells in exchange for a working interests in one well, and cash consideration received by the Company of $1,065,000. The wells are located in DeSoto Parish, Louisiana. The Company recorded a gain on sale of $564,480. The effective date of the exchange was January 1, 2012.
On February 16, 2012, the Company sold certain assets located in Ouachita Parish, Louisiana. The sale consisted of approximately 395 net acres of unproved leasehold in the Cadeville Prospect and one well in progress in exchange for cash consideration of $400,000. The Company recorded a gain on sale of $82,378. The effective date of the sale was February 1, 2012.
On February 7, 2012, the Company acquired working interests in certain sections of the NW Caldwell Prospect located in Caldwell County, Texas, for cash consideration of $1,006,201. The acquired leasehold added approximately 1,973 net acres of unproved leasehold to the NW Caldwell Prospect, all of which was subsequently divested on May 17, 2013. The effective date of the acquisition was January 25, 2012.
2011 Divestitures
On December 1, 2011, the Company sold assets located in Marion, Covington, Jefferson, Warren, and Davis Counties, Mississippi for total cash consideration of $1,228,000 (less post-closing adjustments of $40,707). The sale was comprised of approximately 582 net acres and 16 producing wells. The Company recognized a loss on the sale totaling $3,064,617.
On September 1, 2011, the Company completed the sale of a portion of its assets located in Jackson and Lincoln Parishes, Louisiana for total cash consideration of $950,000. The sale was comprised of approximately 623 net acres and six producing wells. The Company recognized a loss on the sale of $2,291,062.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments.
The Company does not enter into derivative contracts for speculative trading purposes.
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company’s current derivative contracts are lenders in the Company’s Credit Agreement. The Company did not post collateral under any of these contracts
as they are secured under the Company’s Credit Agreement.
The Company’s crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts,
as well as all payments and receipts on settled derivative contracts, in “Net gain on derivative contracts” on the Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.
With an individual derivative counterparty, the Company may have multiple hedge positions that span a several-month time period and result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity, and the netted balance is reflected in the Consolidated Balance Sheets as an asset or a liability.
The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the
Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS – CONTINUED
The following table summarizes the location and fair value amounts of all derivative contracts in the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets as of December 31, 2013. The Company did not have derivative contracts as of December 31, 2012 or 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging contracts under ASC Topic 815
|
|
Balance Sheet Location
|
|
Gross Recognized Assets/ Liabilities
|
|
Gross Amounts Offset
|
|
Net Recognized Assets/ Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
Current derivative liabilities
|
|
$ |
(171,761 |
) |
|
$ |
- |
|
|
$ |
(171,761 |
) |
|
|
Noncurrent derivative liabilities
|
|
$ |
(27,816 |
) |
|
$ |
- |
|
|
$ |
(27,816 |
) |
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s Consolidated Statements of Operations:
Derivatives not designated as hedging contracts under ASC Topic 815
|
|
Statement of Operations Location
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(45,267 |
) |
|
|
|
|
|
341,536 |
|
|
|
|
|
$ |
296,269 |
|
|
|
|
|
|
|
|
Period
|
|
Instrument
|
|
Commodity
|
|
Volume in Mmbtu's/ Bbl's
|
|
|
Fixed price
|
|
January 2014 - March 2014
|
|
Swap
|
|
Natural Gas
|
|
|
120,000 |
|
|
$ |
4.040 |
|
January 2014 - March 2014
|
|
Swap
|
|
Natural Gas
|
|
|
120,000 |
|
|
$ |
4.122 |
|
January 2014 - March 2015
|
|
Swap
|
|
Natural Gas
|
|
|
834,000 |
|
|
$ |
4.175 |
|
January 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
|
60,000 |
|
|
$ |
93.850 |
|
January 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
|
64,800 |
|
|
$ |
98.000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. FAIR VALUE MEASUREMENTS
FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.
The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:
Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair
value hierarchy levels for the year ended December 31, 2013.
Fair Value on a Recurring Basis
Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Fair Value on a Recurring Basis – Continued
The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. These measurements were not material to the consolidated financial statements.
The following table sets forth, by fair value hierarchy level, the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2013. There were no derivative instruments at December 31, 2012.
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liabilities
|
|
$ |
- |
|
|
$ |
171,761 |
|
|
$ |
- |
|
|
$ |
171,761 |
|
Noncurrent derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
liabilities
|
|
|
- |
|
|
|
27,816 |
|
|
|
- |
|
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial liabilities
|
|
$ |
- |
|
|
$ |
199,577 |
|
|
$ |
- |
|
|
$ |
199,577 |
|
Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Fair Value on a Nonrecurring Basis
Asset Impairment
Oil and gas properties are measured at fair value on a nonrecurring basis. The impairment charge reduces the oil and gas properties’ carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets.
The Company recorded asset impairments of $9,817,182, $43,907,927 and $15,400,191 on proved properties during the years ended December 31, 2013, 2012, and 2011, respectively.
The Company recorded asset impairments of $2,480,499, $8,567,026, and $18,893,997 on unproved properties during the years ended December 31, 2013, 2012, and 2011, respectively. All of the 2013, 2012, and 2011 impairments were included in impairment expense.
Business Combinations
The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate
of future natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3 “Acquisitions and Divestitures”.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Fair Value on a Nonrecurring Basis – Continued
Asset Retirement Obligation
The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 8, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.
NOTE 6. MEMBERS’ EQUITY
The Company has three classes of membership interests, consisting of:
|
● |
2,608,200 authorized Class A Units, which represent equity interests in the Company. Based on the value of the Contributed Properties of $60,000,000 as of December 21, 2012, 600,000 Class A Units were issued to Encap. Subsequent to title defects claimed and agreed upon during 2013 in the amount of $7,000,000, the value of Contributed Properties, effective December 21, 2012, was reduced from $60,000,000 to $53,000,000, resulting in the retraction of 70,000 Class A Units previously issued to Encap on December 21, 2012. During 2013, the Company issued 1,034,920 of Class A Units pursuant to capital call
notices. As of December 31, 2013, there were 1,564,920 Class A Units outstanding. Please see the subsection titled “Capital Call Notices” and the consolidated chart below for the activity related to the Class A Units for the years ended December 31, 2013 and 2012. |
|
|
|
|
● |
67,300 authorized Class B Units, which represent equity interests in the Company. As of December 31, 2012, there were no Class B Units outstanding. During 2013, the Company issued 40,380 Class B Units. OVM is an entity controlled by Frank Lodzinski, the Company’s CEO and President, and facilitates investments from the Company’s management team and certain employees to the Company. Please see the subsection titled “Capital Call Notices” and the consolidated
chart below for activity related to the issuance of Class B Units for the years ended December 31, 2013 and 2012. |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. MEMBERS’ EQUITY – CONTINUED
|
● |
100,000 authorized Class C Membership Interests (“Class C Units”), which represent “profit interests” in the Company. On December 21, 2012, all of the authorized Class C Units were issued to OVM. Class C Units entitle OVM to receive distributions from the Company if certain previously agreed upon equity returns are achieved. |
The allocation of income, losses, and distributions are consistent with the Company’s LLC Agreement. The Company’s Board of Managers consist of three representatives from EnCap, one representative from VILLco, and one representative from OVM.
Capital Call Notices
On January 8, 2013, the Company received cash investments in the amount of $16,800,000 related to its first capital call notice sent to Wells Fargo, VILLco, and OVM, resulting in the issuance of 151,200 Class A Units and 16,800 Class B Units.
On May 20, 2013, the Company received cash investments in the amount of $23,720,000 related to its second capital call notice to Investors, resulting in the issuance of 231,670 Class A Units and 5,530 Class B Units.
On June 25, 2013, the Company received cash investments in the amount of $67,010,000 related to its third capital call notice to Investors, resulting in the issuance of 652,050 Class A Units and 18,050 Class B Units.
The following tables summarizes the number of units and the associated dollar value attributable to the Contributed Properties and capital call notices.
|
|
Class A Units
|
|
|
Class B Units
|
|
|
Total Units
|
|
|
|
Units
|
|
|
Dollar Value
|
|
|
Units
|
|
|
Dollar Value
|
|
|
Units
|
|
|
Dollar Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
600,000 |
|
|
$ |
61,267,174 |
|
|
|
- |
|
|
$ |
- |
|
|
|
600,000 |
|
|
$ |
61,267,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustment to Contributed Properties valuation
|
|
|
(70,000 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(70,000 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First capital call
|
|
|
151,200 |
|
|
|
15,120,000 |
|
|
|
16,800 |
|
|
|
1,680,000 |
|
|
|
168,000 |
|
|
|
16,800,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second capital call
|
|
|
231,670 |
|
|
|
23,167,000 |
|
|
|
5,530 |
|
|
|
553,000 |
|
|
|
237,200 |
|
|
|
23,720,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third capital call
|
|
|
652,050 |
|
|
|
65,205,000 |
|
|
|
18,050 |
|
|
|
1,805,000 |
|
|
|
670,100 |
|
|
|
67,010,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,564,920 |
|
|
$ |
164,759,174 |
|
|
|
40,380 |
|
|
$ |
4,038,000 |
|
|
|
1,605,300 |
|
|
$ |
168,797,174 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7. LONG-TERM DEBT
On April 28, 2008, Destiny entered into a $40,000,000 senior secured revolving credit facility (“Destiny Credit Facility”). The Destiny Credit Facility was secured by substantially all of Destiny’s oil and gas properties. On April 21, 2011, all of the membership interests in Destiny were assigned to OVE, and OVE assumed the Destiny Credit Facility.
On June 29, 2011, OVE entered into a new four-year senior secured revolving credit facility (the “OVE Credit Facility”), and OVE assumed the outstanding balance of the Destiny Credit Facility. The OVE Credit Facility was subsequently assumed by OVR on December 21, 2012, the date upon which all of the membership interests in OVE were assigned to OVR. As of December 31, 2012, the borrowing base was $11,000,000, outstanding borrowings totaled $10,825,000, and outstanding letters of credit totaled $175,000.
On July 10, 2013, the Company entered into an amended and restated credit agreement (the “OVR Credit Facility”) which matures on June 29, 2017. BOKF, NA dba Bank of Texas and Wells Fargo Bank, National Association serve as lenders. All of the obligations under the OVR Credit Facility are secured by substantially all of the Company’s assets. The initial borrowing base of the OVR Credit Facility was $15,000,000, subject to scheduled redeterminations on May 1 and November 1 of each year as well as unscheduled redeterminations. In July 2013, the Company initiated an unscheduled
redetermination due to the Eagle Ford Acquisition. The borrowing base increased to $39,500,000 on July 19, 2013, and subsequently increased to $44,500,000 on August 19, 2013. The borrowing base was reaffirmed at $44,500,000 in November 2013. As of December 31, 2013, the borrowing base was $44,500,000, outstanding borrowings totaled $10,825,000, and there were no outstanding letters of credit.
Outstanding borrowings under the OVR Credit Facility and the OVE Credit Facility, at the election of the Company, can bear interest at the LIBOR adjusted rate plus the applicable utilization margin of 2.25% to 4.25% (2.42%, 2.96% and 2.51% at December 31, 2013, 2012, and 2011, respectively) or at the base rate plus the applicable utilization-based margin of 1.00% to 3.00% (4.25%, 4.75% and 4.25% at December 31, 2013, 2012, and 2011, respectively). The Company pays a
commitment rate of 0.500% on all unused borrowings.
The OVR Credit Facility and the OVE Credit Facility contain a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum current ratio of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. As of December 31, 2013 and 2012, the Company was in compliance with these covenants. The
Company is also required to submit an audited annual report 120 days after the end of each fiscal period. For fiscal year 2013, the Company received a waiver, which extended the deadline to provide an audited annual report to July 31, 2014.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7. LONG-TERM DEBT – CONTINUED
Debt issuance costs of $524,023 and $202,328 associated with the Company’s credit facilities have been capitalized as of December 31, 2013 and 2012, respectively, and are amortized on a straight-line basis over the term of the credit agreement. Amortization expense was $103,513, $47,811, and $31,288 for the years ended December 31, 2013, 2012, and 2011, respectively, and is included in “Interest expense” of the Consolidated Statements of Operations.
NOTE 8. ASSET RETIREMENT OBLIGATIONS
The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations:
|
|
|
|
|
|
|
|
|
2012
|
|
Beginning asset retirement obligation
|
|
$ |
3,937,743 |
|
|
$ |
3,692,750 |
|
Acquisitions (1)
|
|
|
609,330 |
|
|
|
- |
|
Liabilities incurred
|
|
|
316,345 |
|
|
|
112,396 |
|
Accretion expense
|
|
|
216,599 |
|
|
|
178,802 |
|
Disposal of properties
|
|
|
(109,641 |
) |
|
|
(674,656 |
) |
Revision of estimates
|
|
|
(1,958,922 |
) |
|
|
628,451 |
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation
|
|
$ |
3,011,454 |
|
|
$ |
3,937,743 |
|
(1) See Note 3, "Acquisitions and Divestitures" for additional information on the Company's acquisition activities.
|
Based on expected timing of settlement, $69,956 of the asset retirement obligation is classified as current at December 31, 2013. At December 31, 2012, all amounts were classified as noncurrent.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9. RELATED PARTY TRANSACTIONS
FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. EnCap, the members of OVM, and Private Placement Investors are considered related parties under ASC Topic 850. The following are significant related party transactions between the Company and parties of Encap and the members of OVM as of and for the years ended December 31, 2013, 2012, and 2011 as well as significant related party transactions between the
Company and the Private Placement Investors as of and for the year ended December 31, 2013.
The Company employs members of OVM. For the years ended December 31, 2013 and 2012, the Company made payments totaling $2,183,717 and $290,044, respectively, to these members as compensation for services and reimbursement of expenses. The payments are included in “General and administrative expense” on the Consolidated Statements of Operations or have been charged out to oil and gas properties. OVM did not provide services to the Company during 2011.
At December 31, 2013, the Company had a liability of $730,384 due to members of OVM, which is included in “Accrued expenses” on the Consolidated Balance Sheet. At December 31, 2012, the Company did not have a related party asset due from OVM members or a related party liability due to OVM members.
At December 31, 2013, the Company had a liability of $627,586 due to companies to which certain Private Placement Investors are significant related parties, which is included in “Accounts payable” on Consolidated Balance Sheet.
As described in Note 6, “Members’ Equity”, all of the authorized Class C Units were issued to OVM. Class C Units entitle OVM to receive distributions from the Company if certain previously agreed upon equity returns are achieved.
As described in Note 2 “Summary of Significant Accounting Policies”, on December 21, 2012, EnCap assigned all the membership interests in ECC VI and OVE to the Company. These transfers were recorded by the Company at the carrying amounts of the assets and liabilities contributed.
For the years ended December 31, 2012 and 2011, the Company incurred general and administrative expenses of approximately $240,000 and $360,000, respectively, related to services provided by Talon Oil and Gas, LLC, a subsidiary of EnCap. Talon Oil and Gas, LLC did not provide services to the Company during 2013. For the years ended December 31, 2013, 2012, and 2011, the Company incurred general and administrative expenses of $36,281,
$57,736, and $51,127, respectively, related to services provided by Foothills Minerals, LLC., a subsidiary of Encap. For the years ended December 31, 2013, 2012, and 2011, the Company incurred overhead costs of $41,301, $165,585, and $158,871, respectively, related to services provided by Foothills Minerals, LLC, which is included in “Lease operating expense” on the Consolidated Statements of Operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10. COMMITMENTS AND CONTINGENCIES
In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation.
Well Control Incident
In December 2012, the Company was notified about a well control issue related to one of its non-operated wells. At December 31, 2012, the Company accrued a liability due to the operator and recorded a receivable from the Company’s insurance carrier, of approximately $470,000, which represents the costs incurred related to the well control issue through December 31, 2012. During 2013, the Company incurred additional costs and received insurance proceeds of $922,978. The insurance proceeds reduced the
capital costs incurred on the non-operated well. The Company does not expect to receive additional proceeds.
There are no other matters, which in the opinion of the Company’s management, will have a material adverse effect on the consolidated financial position, consolidated results of operations, or consolidated cash flows of the Company as of and for the years ended December 31, 2013, 2012, and 2011.
Gas Purchase and Gas Processing Contract
As a part of the Eagle Ford Acquisition discussed in Note 3 “Acquisitions and Divestitures”, the Company ratified several long-term gas purchasing and gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company has a volume commitment, whereby the Company pays the owner of the pipeline a
fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity for the Company’s use. Since the time of the acquisition, the Company has not been able to meet its delivery commitments. The rate and terms under this purchasing and processing contract expire on June 1, 2021.
Drilling Commitments
As of December 31, 2013, the Company had two drilling rigs under contract in the Eagle Ford. The Company contractually agreed to drill two wells at a drilling day rate of approximately $19,700 per day and another two wells at a drilling day rate of approximately $20,700 per day. As of December 31, 2013, drilling had commenced on two wells. Early termination of both drilling rig contracts prior to the commencement of operations would require termination payments of approximately $677,000,
which would be paid in lieu of paying the remaining drilling commitments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10. COMMITMENTS AND CONTINGENCIES – CONTINUED
Lease Commitments
In April 2013, the Company entered into a three year lease agreement for office space in Houston, Texas, with an option to terminate the lease on July 31, 2014 and April 30, 2015, provided the Company gives the lessor six months’ notice. In January 2014, the Company gave written notice to the landlord to exercise the termination option and negotiated an extension of the first termination date. The Company’s lease will effectively terminate on November 30,
2014. The Company is contractually obligated under the office lease to make payments totaling $232,437 during 2014.
In September 2013, the Company entered into a seven month lease agreement for office space in Denver, Colorado, with an entity controlled by the principals of VILLco. As discussed in Note 2 “Summary of Significant Accounting Policies”, VILLco is a related party. As of December 31, 2013, the Company is contractually obligated under the office lease to make payments totaling $6,428 during 2014. On March 10, 2014, the Company exercised an option to extend the lease for six months. Please see Note 12 “Subsequent Events” for additional information.
Rent expense under non-cancellable operating leases was $121,208, $83,000, and $38,850 for the years ended December 31, 2013, 2012, and 2011, respectively.
Environmental
The Company’s operations are subject to risks normally associated with the exploration for and the production of oil and gas, including blowouts, fires, and environmental risks such as oil spills or gas leaks that could expose the Company to liabilities associated with these risks.
In the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of prior environmental safeguards, if any, that were taken at the time such wells were drilled or during such time the wells were operated. The Company maintains comprehensive insurance coverage that it believes is adequate to mitigate the risk of any adverse financial effects associated with these risks.
However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon the Company. No claim has been made, nor is the Company aware of any liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations relating thereto except for the matter discussed above.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Costs Incurred Related to Oil and Gas Activities
The Company’s oil and gas activities for 2013, 2012, and 2011 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows:
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Acquisition costs: |
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
51,487,762 |
|
|
$ |
1,608,671 |
|
|
$ |
1,876,710 |
|
Unproved
|
|
|
32,863,367 |
|
|
|
11,589,199 |
|
|
|
4,542,660 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory drilling
|
|
|
63,803 |
|
|
|
2,013,376 |
|
|
|
18,569 |
|
Geological and geophysical
|
|
|
393,917 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development costs
|
|
|
32,510,927 |
|
|
|
24,221,422 |
|
|
|
15,067,920 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total additions
|
|
$ |
117,319,776 |
|
|
$ |
39,432,668 |
|
|
$ |
21,505,859 |
|
The net changes in capitalized exploratory wells cost were as follows:
|
|
December 31, |
|
|
|
|
|
|
2012
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
$ |
2,031,945 |
|
|
$ |
18,569 |
|
|
$ |
11,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
|
63,803 |
|
|
|
2,013,376 |
|
|
|
18,569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized exploratory well costs charged to expense
|
|
|
(2,095,748 |
) |
|
|
- |
|
|
|
(11,185 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$ |
- |
|
|
$ |
2,031,945 |
|
|
$ |
18,569 |
|
Estimated Quantities of Proved Oil and Gas Reserves
For the years ended December 31, 2013 and 2012, the estimate of proved reserves and related valuations were based on reports prepared by the Company’s independent petroleum engineers, Cawley, Gillespie & Associates, Inc. In connection with the Company’s external petroleum engineers performing their independent reserve estimations, the Company furnished the following information: (1) technical support data, (2) technical analysis of geological and engineering support information, (3) economic and production data and (4) our ownership interests. Proved reserve estimates included
herein conform to the definitions prescribed by the U.S. Securities and Exchange Commission. For the years ended December 31, 2011 and 2010, the estimate of proved reserves and related valuations were based on reserve reports prepared by the Company as well as reserve reports prepared by various independent petroleum engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – CONTINUED
Estimated Quantities of Proved Oil and Gas Reserves – Continued
Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions existing as of the end of each respective year. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods.
|
|
Oil
|
|
|
|
|
Natural Gas
|
|
|
NGLs
|
|
|
Total
|
|
|
|
(Bbl)
|
|
|
|
|
(Mcf)
|
|
|
(Bbl)
|
|
|
(BOE)
|
|
|
|
|
1,500,827 |
|
|
|
|
|
106,755,881 |
|
|
|
- |
|
|
|
19,293,474 |
|
Extensions and discoveries
|
|
|
- |
|
|
|
|
|
9,597 |
|
|
|
- |
|
|
|
1,600 |
|
Sale of minerals in place
|
|
|
(16,000 |
) |
|
|
|
|
(608,200 |
) |
|
|
- |
|
|
|
(117,367 |
) |
Production
|
|
|
(68,692 |
) |
|
|
|
|
(3,088,658 |
) |
|
|
- |
|
|
|
(583,468 |
) |
Revision to previous estimates
|
|
|
(234,366 |
) |
|
|
|
|
(46,609,638 |
) |
|
|
- |
|
|
|
(8,002,639 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,181,769 |
|
|
|
|
|
56,458,982 |
|
|
|
- |
|
|
|
10,591,600 |
|
Extensions and discoveries
|
|
|
407,343 |
|
|
|
|
|
3,595,669 |
|
|
|
299,062 |
|
|
|
1,305,683 |
|
Sale of minerals in place
|
|
|
(301,133 |
) |
|
|
|
|
(165,372 |
) |
|
|
- |
|
|
|
(328,695 |
) |
Production
|
|
|
(90,410 |
) |
|
|
|
|
(2,297,554 |
) |
|
|
(75,744 |
) |
|
|
(549,080 |
) |
Revision to previous estimates
|
|
|
(679,144 |
) |
|
|
|
|
(47,492,560 |
) |
|
|
168,988 |
|
|
|
(8,425,583 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
518,425 |
|
|
|
|
|
10,099,165 |
|
|
|
392,306 |
|
|
|
2,593,925 |
|
Extensions and discoveries
|
|
|
3,586,369 |
|
|
|
|
|
4,197,687 |
|
|
|
526,076 |
|
|
|
4,812,060 |
|
Sale of minerals in place
|
|
|
(14,589 |
) |
|
|
|
|
- |
|
|
|
- |
|
|
|
(14,589 |
) |
Purchases of minerals in place
|
|
|
2,051,245 |
|
|
|
|
|
708,729 |
|
|
|
213,404 |
|
|
|
2,382,771 |
|
Production
|
|
|
(163,115 |
) |
|
|
|
|
(2,635,417 |
) |
|
|
(134,408 |
) |
|
|
(736,759 |
) |
Revision to previous estimates
|
|
|
99,856 |
|
|
|
|
|
11,842,621 |
|
|
|
321,070 |
|
|
|
2,394,696 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,078,191 |
|
|
|
|
|
24,212,785 |
|
|
|
1,318,448 |
|
|
|
11,432,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
543,140 |
|
|
|
|
|
24,055,343 |
|
|
|
- |
|
|
|
4,552,364 |
|
|
|
|
569,693 |
|
|
|
|
|
17,526,196 |
|
|
|
- |
|
|
|
3,490,726 |
|
|
|
|
296,250 |
|
|
|
|
|
8,244,891 |
|
|
|
268,470 |
|
|
|
1,938,869 |
|
|
|
|
1,306,922 |
|
|
|
|
|
11,052,891 |
|
|
|
557,061 |
|
|
|
3,706,132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
957,687 |
|
|
|
|
|
82,700,538 |
|
|
|
- |
|
|
|
14,741,110 |
|
|
|
|
612,076 |
|
|
|
|
|
38,932,786 |
|
|
|
- |
|
|
|
7,100,874 |
|
|
|
|
222,175 |
|
|
|
|
|
1,854,274 |
|
|
|
123,836 |
|
|
|
655,056 |
|
|
|
|
4,771,269 |
|
|
|
|
|
13,159,894 |
|
|
|
761,387 |
|
|
|
7,725,972 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – CONTINUED
Estimated Quantities of Proved Oil and Gas Reserves – Continued
|
● |
Extensions and discoveries. The 2012 increase in extensions and discoveries of 1,305,683 BOE was primarily attributable to the Company’s non-operated Eagle Ford fields. The 2013 increase in extensions and discoveries of 4,812,060 BOE was primarily attributable to an increase of 818,000 BOE in our non-operated Eagle Ford fields and an increase of 3,918,000 BOE in our operated Eagle Ford field. The 2012 and 2013 increases are a result of successful drilling. |
|
|
|
|
● |
Sale of minerals in place. The decreases in sale of minerals in place of 117,367 BOE, 328,695 BOE, and 14,589 BOE in 2011, 2012, and 2013, respectively, are attributable to the sale of non-core assets discussed in Note 3 “Acquisitions and Divestitures”. |
|
|
|
|
● |
Revision to previous estimates. The 2011 downward revision to previous estimates of 8,002,639 BOE was primarily attributable to a downward revision in PUDs in certain gas fields. The 2012 downward revision of 8,425,583 BOE was primarily attributable to lower natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011. The 2013 positive revision to previous estimates of 2,394,696 BOE was primarily attributable to the increase in natural gas prices from December 31, 2012 to the reserve estimates performed at December 31, 2013.
Revisions to PUD reserves were 2,016,330 BOE as a result of this increase in natural gas prices. |
Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flow to provide oil and natural gas reserves were prepared in accordance with ASC 932, Extractive Activities—Oil and Gas and based on oil and natural gas reserve and production volumes. Future cash inflows as of December 31, 2013, 2012, and 2011 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2013, 2012, and 2011,
respectively) to estimated future production. The oil and natural gas liquids prices were adjusted by lease or field for quality, transportation fees, and regional price differentials. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) – CONTINUED
Discounted Future Net Cash Flows – Continued
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:
|
|
|
|
|
|
|
|
|
2012
|
|
|
2011
|
|
Future cash inflows
|
|
$ |
718,048,500 |
|
|
$ |
88,234,062 |
|
|
$ |
320,507,627 |
|
Future production costs
|
|
|
(202,956,656 |
) |
|
|
(32,966,585 |
) |
|
|
(96,744,544 |
) |
Future development costs
|
|
|
(220,828,406 |
) |
|
|
(15,270,532 |
) |
|
|
(70,073,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
294,263,438 |
|
|
|
39,996,945 |
|
|
|
153,689,535 |
|
10% annual discount for estimated timing of cash flows
|
|
|
(168,906,757 |
) |
|
|
(14,864,480 |
) |
|
|
(84,449,284 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$ |
125,356,681 |
|
|
$ |
25,132,465 |
|
|
$ |
69,240,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:
|
December 31, |
|
|
|
|
|
2012
|
|
|
2011
|
|
Beginning of year
|
|
$ |
25,132,465 |
|
|
$ |
69,240,251 |
|
|
$ |
93,855,420 |
|
Sales of oil and gas produced, net of production costs
|
|
|
(20,287,228 |
) |
|
|
(10,300,405 |
) |
|
|
(11,987,811 |
) |
Sales of minerals in place
|
|
|
(379,816 |
) |
|
|
(10,274,368 |
) |
|
|
(1,815,800 |
) |
Net changes in prices and production costs
|
|
|
240,869 |
|
|
|
(6,132,807 |
) |
|
|
3,248,829 |
|
Extensions, discoveries, and improved recoveries
|
|
|
48,006,461 |
|
|
|
16,374,985 |
|
|
|
8,817 |
|
Previously estimated development costs incurred during the period
|
|
|
3,226,661 |
|
|
|
- |
|
|
|
2,853,000 |
|
Net changes in future development costs
|
|
|
(22,965,928 |
) |
|
|
14,786,676 |
|
|
|
4,157,138 |
|
Purchases of minerals in place
|
|
|
56,068,939 |
|
|
|
- |
|
|
|
- |
|
Revisions of previous quantity estimates
|
|
|
26,258,514 |
|
|
|
(54,774,777 |
) |
|
|
(36,675,214 |
) |
Accretion of discount
|
|
|
2,513,247 |
|
|
|
6,924,025 |
|
|
|
9,385,542 |
|
Changes in timing of estimated cash flows and other
|
|
|
7,542,497 |
|
|
|
(711,115 |
) |
|
|
6,210,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$ |
125,356,681 |
|
|
$ |
25,132,465 |
|
|
$ |
69,240,251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices, used in standardized measure
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$ |
96.94 |
|
|
$ |
94.71 |
|
|
$ |
96.19 |
|
Gas (per Mcf)
|
|
$ |
3.67 |
|
|
$ |
2.75 |
|
|
$ |
4.12 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUBSEQUENT EVENTS
Transaction Date |
|
Period |
|
Instrument |
|
Commodity |
|
Volume in Mmbtu's/ Bbl's
|
|
|
Fixed Price
|
|
|
|
April 2014 - March 2015
|
|
Swap
|
|
Natural Gas
|
|
|
525,000 |
|
|
$ |
4.30 |
|
|
|
April 2014 - December 2014
|
|
Swap
|
|
Natural Gas
|
|
|
450,000 |
|
|
$ |
4.55 |
|
|
|
February 2014 - June 2014
|
|
Swap
|
|
Crude Oil
|
|
|
25,000 |
|
|
$ |
95.50 |
|
|
|
April 2014 - December 2014
|
|
Swap
|
|
Natural Gas
|
|
|
77,220 |
|
|
$ |
4.60 |
|
|
|
February 2014 - June 2014
|
|
Swap
|
|
Crude Oil
|
|
|
25,000 |
|
|
$ |
98.60 |
|
|
|
January 2015 - June 2015
|
|
Swap
|
|
Crude Oil
|
|
|
21,000 |
|
|
$ |
91.50 |
|
|
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
|
30,000 |
|
|
$ |
95.65 |
|
|
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
|
31,200 |
|
|
$ |
98.55 |
|
|
|
June 2014 - June 2014
|
|
Swap
|
|
Crude Oil
|
|
|
1,800 |
|
|
$ |
102.35 |
|
|
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
|
9,600 |
|
|
$ |
100.05 |
|
|
|
January 2015 - December 2015
|
|
Swap
|
|
Crude Oil
|
|
|
66,000 |
|
|
$ |
95.10 |
|
On January 30 2014, the Company exercised the option to terminate the lease for the Houston, Texas office space, discussed in Note 10 “Commitments and Contingencies”. The Company’s lease will effectively terminate on November 30, 2014.
On February 4, 2014 and March 8, 2014, the Company amended one of the drilling contracts discussed in Note 10 “Commitments and Contingencies” to reflect the drilling of seven additional wells at a drilling day rate of approximately $19,200 per day.
On April 6, 2014, the Company amended one of the drilling contracts discussed in Note 10 “Commitments and Contingencies”, to reflect the drilling of five additional wells at a drilling day rate of approximately $22,700 per day.
On May 15, 2014, Earthstone Energy, Inc. (“Earthstone”) and OVR entered into a definitive exchange agreement under which Earthstone will acquire all the subsidiaries of OVR in exchange for approximately 9.1 million shares of Earthstone common stock (the “Transaction”). The closing of the Transaction is subject to the approval of Earthstone stockholders. OVR’s management team will assume the same roles in the combined company.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUBSEQUENT EVENTS – CONTINUED
On May 27, 2014, the Company entered into a 61 month lease agreement for office space in The Woodlands, Texas. The Company is contractually obligated under the office lease to make payments totaling $3,041,887. The lease will commence upon completion of a leasehold build out which is expected to be completed during the fourth quarter of 2014.
Unaudited Financial Statements of Oak Valley Resources, LLC as of and for the Six Months Ended June 30, 2014 and 2013
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
(Unaudited) |
|
|
2013 |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
|
|
|
Cash
|
|
$ |
32,035,308 |
|
|
$ |
25,422,741 |
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids revenues
|
|
|
12,121,154 |
|
|
|
8,121,930 |
|
Joint interest billings and other
|
|
|
8,671,019 |
|
|
|
7,541,245 |
|
Prepaid expenses and other assets
|
|
|
457,586 |
|
|
|
122,104 |
|
Current derivative assets
|
|
|
7,444 |
|
|
|
154,310 |
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
53,292,511 |
|
|
|
41,362,330 |
|
|
|
|
|
|
|
|
|
|
OIL AND GAS PROPERTIES, successful efforts method
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
210,977,471 |
|
|
|
184,075,412 |
|
Unproved properties
|
|
|
45,334,381 |
|
|
|
43,010,521 |
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties
|
|
|
256,311,852 |
|
|
|
227,085,933 |
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion, and amortization
|
|
|
(87,409,925 |
) |
|
|
(79,788,805 |
) |
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
168,901,927 |
|
|
|
147,297,128 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT ASSETS
|
|
|
|
|
|
|
|
|
Office and other equipment, less accumulated depreciation of $333,038 and $191,088, respectively
|
|
|
647,281 |
|
|
|
560,477 |
|
Noncurrent derivative assets
|
|
|
6,204 |
|
|
|
- |
|
Other noncurrent assets
|
|
|
678,643 |
|
|
|
537,752 |
|
Land
|
|
|
100,637 |
|
|
|
100,637 |
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$ |
223,627,203 |
|
|
$ |
189,858,324 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$ |
12,988,858 |
|
|
$ |
7,428,304 |
|
Accrued expenses
|
|
|
5,660,883 |
|
|
|
5,768,144 |
|
Revenues and royalties payable
|
|
|
17,566,475 |
|
|
|
10,184,145 |
|
Advances
|
|
|
18,961,110 |
|
|
|
3,519,881 |
|
Current derivative liabilities
|
|
|
1,273,321 |
|
|
|
171,761 |
|
Asset retirement obligations
|
|
|
66,625 |
|
|
|
69,956 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
56,517,272 |
|
|
|
27,142,191 |
|
|
|
|
|
|
|
|
|
|
NONCURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Noncurrent derivative liabilities
|
|
|
- |
|
|
|
27,816 |
|
Long-term debt
|
|
|
10,825,000 |
|
|
|
10,825,000 |
|
Asset retirement obligations
|
|
|
3,093,378 |
|
|
|
2,941,498 |
|
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities
|
|
|
13,918,378 |
|
|
|
13,794,314 |
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
70,435,650 |
|
|
|
40,936,505 |
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Note 9)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MEMBERS' EQUITY
|
|
|
153,191,553 |
|
|
|
148,921,819 |
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND MEMBERS' EQUITY
|
|
$ |
223,627,203 |
|
|
$ |
189,858,324 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
|
|
Three Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas, and natural gas liquids revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$ |
8,508,149 |
|
|
$ |
2,041,440 |
|
|
$ |
16,376,135 |
|
|
$ |
3,125,858 |
|
Natural gas
|
|
|
2,592,916 |
|
|
|
3,045,108 |
|
|
|
5,346,301 |
|
|
|
4,630,947 |
|
Natural gas liquids
|
|
|
957,177 |
|
|
|
1,122,331 |
|
|
|
1,913,527 |
|
|
|
1,562,190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil, natural gas, and natural gas liquids revenues |
|
|
12,058,242 |
|
|
|
6,208,879 |
|
|
|
23,635,963 |
|
|
|
9,318,995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and other income
|
|
|
86,289 |
|
|
|
133,422 |
|
|
|
195,270 |
|
|
|
249,862 |
|
Loss on sales of oil and gas properties
|
|
|
- |
|
|
|
(54,365 |
) |
|
|
- |
|
|
|
(54,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
12,144,531 |
|
|
|
6,287,936 |
|
|
|
23,831,233 |
|
|
|
9,514,492 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
2,375,541 |
|
|
|
2,200,070 |
|
|
|
4,674,008 |
|
|
|
3,446,845 |
|
Severance taxes |
|
|
508,809 |
|
|
|
236,169 |
|
|
|
997,956 |
|
|
|
345,020 |
|
Re-engineering and workovers
|
|
|
121,580 |
|
|
|
115,830 |
|
|
|
319,523 |
|
|
|
144,219 |
|
Depreciation, depletion, and amortization
|
|
|
4,382,921 |
|
|
|
6,201,364 |
|
|
|
7,763,070 |
|
|
|
8,998,008 |
|
Impairment expense
|
|
|
- |
|
|
|
44,372 |
|
|
|
- |
|
|
|
44,372 |
|
Exploration expense
|
|
|
- |
|
|
|
389,610 |
|
|
|
- |
|
|
|
1,666,943 |
|
General and administrative expense
|
|
|
1,802,185 |
|
|
|
1,507,384 |
|
|
|
3,213,760 |
|
|
|
3,099,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
9,191,036 |
|
|
|
10,694,799 |
|
|
|
16,968,317 |
|
|
|
17,744,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
2,953,495 |
|
|
|
(4,406,863 |
) |
|
|
6,862,916 |
|
|
|
(8,229,962 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSES)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(152,092 |
) |
|
|
(101,650 |
) |
|
|
(297,238 |
) |
|
|
(195,178 |
) |
|
|
|
(1,274,786 |
) |
|
|
295,080 |
|
|
|
(2,302,699 |
) |
|
|
226,733 |
|
Interest income
|
|
|
- |
|
|
|
(900 |
) |
|
|
- |
|
|
|
- |
|
Other income (expenses), net
|
|
|
3,226 |
|
|
|
39,307 |
|
|
|
6,755 |
|
|
|
58,916 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expenses) |
|
|
(1,423,652 |
) |
|
|
231,837 |
|
|
|
(2,593,182 |
) |
|
|
90,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
|
|
$ |
1,529,843 |
|
|
$ |
(4,175,026 |
) |
|
$ |
4,269,734 |
|
|
$ |
(8,139,491 |
) |
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
(UNAUDITED)
|
|
Members' Equity
|
|
|
|
|
|
|
|
$ |
61,267,174 |
|
|
|
|
|
|
Net loss
|
|
|
(8,139,491 |
) |
|
|
|
|
|
Members' equity contributions
|
|
|
68,845,000 |
|
|
|
|
|
|
|
|
$ |
121,972,683 |
|
|
|
|
|
|
|
|
$ |
148,921,819 |
|
|
|
|
|
|
Net income
|
|
|
4,269,734 |
|
|
|
|
|
|
|
|
$ |
153,191,553 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
4,269,734 |
|
|
$ |
(8,139,491 |
) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
7,763,070 |
|
|
|
8,998,008 |
|
Impairment of unproved oil and gas properties
|
|
|
- |
|
|
|
44,372 |
|
Dry hole costs
|
|
|
- |
|
|
|
1,277,333 |
|
Accretion of asset retirement obligations
|
|
|
151,111 |
|
|
|
103,455 |
|
Settlement of asset retirement obligation
|
|
|
(31,120 |
) |
|
|
- |
|
Unrealized (gain) loss on derivative contracts
|
|
|
1,214,406 |
|
|
|
(238,215 |
) |
Amortization of deferred financing costs
|
|
|
75,570 |
|
|
|
29,312 |
|
Loss on sale of assets
|
|
|
- |
|
|
|
54,365 |
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Increase in accounts receivable
|
|
|
(5,128,998 |
) |
|
|
(2,376,826 |
) |
Increase in prepaid expense and other
|
|
|
(450,190 |
) |
|
|
(142,153 |
) |
Increase (decrease) in accounts payable and accrued expenses
|
|
|
5,453,293 |
|
|
|
(922,433 |
) |
Increase in revenue and royalties payable
|
|
|
7,382,330 |
|
|
|
357,619 |
|
Increase in advances
|
|
|
15,441,229 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
36,140,435 |
|
|
|
(954,654 |
) |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Additions to oil and gas property and equipment
|
|
|
(29,197,361 |
) |
|
|
(13,726,069 |
) |
Additions to other property and equipment
|
|
|
(228,754 |
) |
|
|
(386,759 |
) |
Proceeds from sales of oil and gas properties
|
|
|
- |
|
|
|
487,471 |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(29,426,115 |
) |
|
|
(13,625,357 |
) |
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Deferred financing costs
|
|
|
(101,753 |
) |
|
|
(41,079 |
) |
Contributions
|
|
|
- |
|
|
|
68,845,000 |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(101,753 |
) |
|
|
68,803,921 |
|
|
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
6,612,567 |
|
|
|
54,223,910 |
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, at beginning of period
|
|
|
25,422,741 |
|
|
|
20,151,399 |
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, at end of period
|
|
$ |
32,035,308 |
|
|
$ |
74,375,309 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(CONTINUED)
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL CASH FLOW INFORMATION
|
|
|
|
|
|
|
Interest paid
|
|
$ |
220,968 |
|
|
$ |
156,456 |
|
|
|
|
|
|
|
|
|
|
DISCLOSURE OF NON-CASH INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$ |
28,558 |
|
|
$ |
150,839 |
|
The Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1. ORGANIZATION AND BUSINESS
Oak Valley Resources, LLC (“OVR” or the “Company”), is a Delaware limited liability company formed on December 14, 2012. OVR is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil, natural gas, and natural gas liquids (“NGL”). The Company currently has properties in Texas, Oklahoma, and Louisiana.
NOTE 2. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”) for interim financial statements. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. In the opinion of the Company’s management, the accompanying consolidated financial contain all normal and recurring adjustments considered necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report for the year ended December 31, 2013.
All intercompany accounts and transactions are eliminated upon consolidation.
Subsequent Events
Management has evaluated subsequent events for the Company through August 28, 2014, the date upon which these consolidated financial statements were available to be issued. Please see Note 10 “Subsequent Events” for the results of that evaluation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 2. BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION – CONTINUED
Use of Estimates
The preparation of the Company's consolidated financial statements in conformity with US GAAP requires the Company's management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of the Company’s management are significant include oil and natural gas reserves and the related cash flow estimates used in depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for
impairment, fair value estimates, asset retirement obligations, oil and natural gas revenue accruals, lease operating expense accruals, and capital accruals. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company's operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company's consolidated
financial statements.
Recently Issued Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. ASU 2014-09 must be applied retrospectively and is effective for annual reporting periods, and interim periods with that reporting period, beginning after December 15, 2016. Early adoption is not permitted. The
Company is currently assessing the impact of the adoption of ASU 2014-09 on the Company's operating results, financial position and disclosures.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 3. ACQUISTIONS AND DIVESTITURES
Pending Merger with Earthstone Energy, Inc.
On May 15, 2014, Earthstone Energy, Inc., a Delaware corporation (“Earthstone”) and OVR entered into an Exchange Agreement, whereby OVR will contribute to Earthstone the membership interests of its three wholly-owned subsidiaries, Oak Valley Operating, LLC, EF Non-Op, LLC and Sabine River Energy, LLC, each a Texas limited liability company (collectively, “Oak Valley”), inclusive of producing assets, undeveloped acreage and an estimated $142,500,000 of cash, in exchange for the issuance of approximately 9.1 million shares of Earthstone common stock, par value $0.001 per share (the “Common Stock”), to OVR (the “Exchange”). Following the Exchange, current Earthstone stockholders will own 16% and OVR will own 84% of Earthstone’s outstanding Common Stock, and six of the seven
members of the Board will be persons who are affiliated with OVR.
The Exchange will be accounted for under FASB Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC Topic 805”), as a reverse acquisition for accounting purposes. In the Exchange, Earthstone is the acquirer for legal purposes, but for accounting purposes, Oak Valley will be deemed to be the acquirer and Earthstone the acquiree. As the accounting acquiree, the historical book value of Earthstone’s assets and liabilities will be remeasured and recorded at fair value on the public company’s balance sheet on the date of acquisition.
Eagle Ford Acquisition
In July 2013 and August 2013, the Company purchased producing wells and acreage in the Eagle Ford shale trend in Texas. As disclosed in the Company's Annual Report as of and for the year ended December 31, 2013, the Eagle Ford Acquisition was accounted for as a business combination in accordance with ASC Topic 805 which requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Certain assets and liabilities may be adjusted as additional information is obtained, but no later than one year from the respective acquisition dates. During the six months ended June 30, 2014, as a result of more accurate information obtained during the
period, there were immaterial adjustments to the purchase price of the Eagle Ford Acquisition related to accruals, settlements, and working capital changes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 3. ACQUISTIONS AND DIVESTITURES – CONTINUED
Eagle Ford Acquisition – Continued
The following table provides the purchase price of the acquired properties and its allocation.
Purchase price
|
|
$ |
86,981,378 |
|
|
|
|
|
|
Allocation of purchase price:
|
|
|
|
|
Proved properties
|
|
$ |
57,549,614 |
|
Unproved properties
|
|
|
30,041,094 |
|
Asset retirement obligations
|
|
|
(609,330 |
) |
|
|
|
|
|
Total
|
|
$ |
86,981,378 |
|
The amount of revenue and net income from the Eagle Ford Acquisition included in the Company’s consolidated statement of operations for the three months ended June 30, 2014 was $7,227,984 and $4,389,251, respectively. The amount of revenue and net income from the Eagle Ford Acquisition included in the Company’s consolidated statement of operations for the six months ended June 30, 2014 was $13,541,394 and $8,455,989, respectively. No revenue or net income was recorded for this acquisition during the three or six months ended June 30, 2013.
The following unaudited pro forma combined results of operations are provided for the three and six months ended June 30, 2013 as though the Eagle Ford Acquisition had been completed as of the beginning of the comparable prior interim reporting period, or January 1, 2013. The pro forma combined results of operations for the three months ended June 30, 2013 have been prepared by adjusting the historical results of the Company to include the historical results of the Eagle Ford Acquisition. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the Eagle Ford Acquisition
occurred at the beginning of the period presented. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Eagle Ford Acquisition, or any estimated costs that will be incurred to integrate the Eagle Ford Acquisition. Future results may vary significantly from the results reflected in the following unaudited pro forma financial table because of future events, transactions, and other factors.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 3. ACQUISTIONS AND DIVESTITURES – CONTINUED
Eagle Ford Acquisition – Continued
The Company's historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Eagle Ford Acquisition and that were factually supportable. Adjustments and assumptions made for this pro forma calculation are consistent with those used in the Company's annual pro forma information discussed in Note 3, "Acquisitions and Divestitures" in the Company's Annual Report as of and for the year ended December 31, 2013.
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
Revenue
|
|
$ |
16,119,448 |
|
|
$ |
26,381,964 |
|
Net Income
|
|
$ |
2,838,895 |
|
|
$ |
4,103,146 |
|
2013 Divestitures
On May 17, 2013, the Company sold undeveloped acreage and working interest in nine wells located in Guadalupe County, Texas, and Caldwell County, Texas for cash consideration of $487,371. The Company recorded a loss on sale of $54,465 in the second quarter of 2013. The effective date of the sale was April 1, 2013.
On March 28, 2013, the Company sold undeveloped acreage in Harrison County, Texas, and the working interest in one well for cash consideration of $100. The Company recorded a gain on sale of $100 in the second quarter of 2013. The effective date of the sale was April 1, 2013.
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815, Derivatives and Hedging (“ASC Topic 815”), to account for its derivative financial instruments. The
Company does not enter into derivative contracts for speculative trading purposes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS – CONTINUED
It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The counterparties to the Company's current derivative contracts are lenders in the Company’s Credit Agreement. The Company did not post collateral under any of these contracts
as they are secured under the Company's Credit Agreement.
The Company's crude oil and natural gas derivative positions consist of swaps. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company has elected to not designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts,
as well as all payments and receipts on settled derivative contracts, in "Net gain (loss) on derivative contracts" on the Consolidated Statements of Operations. All derivative contracts are recorded at fair market value and included in the Consolidated Balance Sheets as assets or liabilities.
The Company may have multiple hedge positions, with an individual derivative counterparty, that span several months, which may result in fair value asset and liability positions. At the end of each reporting period, those positions are offset to a single fair value asset or liability for each commodity and the netted balance is reflected in the Consolidated Balance Sheets as an asset or a liability.
The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”), which provides for net settlement over the term of the contract. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. Upon the mutual election of both parties, the ISDA allows the
Company and the respective counterparty to offset amounts payable and receivable related to transactions that have identical terms.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS – CONTINUED
The following table summarizes the location and fair value amounts of all derivative contracts on the Consolidated Balance Sheets as well as the gross recognized derivative assets, liabilities, and amounts offset in the Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013.
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Net
|
|
Derivatives not designated
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Recognized
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
ASC Topic 815
|
|
Balance Sheet Location
|
|
(Liabilities)
|
|
|
Offset
|
|
|
(Liabilities)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
37,726 |
|
|
$ |
(30,282 |
) |
|
$ |
7,444 |
|
|
|
Current derivative liabilities
|
|
|
(1,303,603 |
) |
|
|
30,282 |
|
|
|
(1,273,321 |
) |
|
|
Noncurrent derivative assets
|
|
|
6,204 |
|
|
|
- |
|
|
|
6,204 |
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
|
|
|
Net
|
|
Derivatives not designated
|
|
|
|
Recognized
|
|
|
Gross
|
|
|
Recognized
|
|
|
|
|
|
Assets/
|
|
|
Amounts
|
|
|
Assets/
|
|
ASC Topic 815
|
|
Balance Sheet Location
|
|
(Liabilities)
|
|
|
Offset
|
|
|
(Liabilities)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
Current derivative liabilities
|
|
|
(171,761 |
) |
|
|
- |
|
|
|
(171,761 |
) |
|
|
Noncurrent derivative liabilities
|
|
|
(27,816 |
) |
|
|
- |
|
|
|
(27,816 |
) |
The following table summarizes the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts on the Company's Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013.
|
|
|
|
Gain (Loss) Recognized in Income
|
|
Derivatives not designated as hedging
|
|
Statement of Operations
|
|
Three Months Ended June 30,
|
|
|
|
Location
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on commodity contracts
|
|
|
|
$ |
(725,821 |
) |
|
$ |
306,562 |
|
|
|
|
|
|
(548,965 |
) |
|
|
(11,482 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,274,786 |
) |
|
$ |
295,080 |
|
|
|
|
|
Gain (Loss) Recognized in Income
|
|
Derivatives not designated as hedging
|
|
Statement of Operations
|
|
Six Months Ended June 30,
|
|
|
|
Location
|
|
|
2014 |
|
|
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on commodity contracts
|
|
|
|
$ |
(1,214,406 |
) |
|
$ |
238,215 |
|
|
|
|
|
|
(1,088,293 |
) |
|
|
(11,482 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(2,302,699 |
) |
|
$ |
226,733 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS – CONTINUED
|
|
|
|
|
|
Volume in
|
|
|
|
|
|
|
|
|
Mmbtu's/
|
|
Fixed
|
Period
|
|
Instrument
|
|
Commodity
|
|
Bbl's
|
|
Price
|
|
|
|
|
|
|
|
|
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
30,000
|
|
$ 93.850
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
30,000
|
|
$ 95.650
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
9,600
|
|
$ 100.050
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
31,200
|
|
$ 98.550
|
July 2014 - December 2014
|
|
Swap
|
|
Crude Oil
|
|
32,400
|
|
$ 98.000
|
January 2015 - June 2015
|
|
Swap
|
|
Crude Oil
|
|
21,000
|
|
$ 91.500
|
January 2015 - December 2015
|
|
Swap
|
|
Crude Oil
|
|
66,000
|
|
$ 95.100
|
July 2014 - December 2014
|
|
Swap
|
|
Natural Gas
|
|
51,480
|
|
$ 4.600
|
July 2014 - December 2014
|
|
Swap
|
|
Natural Gas
|
|
300,000
|
|
$ 4.550
|
July 2014 - March 2015
|
|
Swap
|
|
Natural Gas
|
|
375,000
|
|
$ 4.300
|
July 2014 - March 2015
|
|
Swap
|
|
Natural Gas
|
|
450,000
|
|
$ 4.175
|
NOTE 5. FAIR VALUE MEASUREMENTS
FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), defines fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants at the measurement date. ASC Topic 820 provides a framework for measuring fair value, establishes a three level hierarchy for fair value measurements based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date and requires consideration of the counterparty’s creditworthiness when valuing certain assets.
The three-level fair value hierarchy for disclosure of fair value measurements defined by ASC Topic 820 is as follows:
Level 1 – Unadjusted, quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is defined as a market where transactions for the financial instrument occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Inputs, other than quoted prices within Level 1, that are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Level 3 – Prices or valuations that require unobservable inputs that are both significant to the fair value measurement and unobservable. Valuation under Level 3 generally involves a significant degree of judgment from management.
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instrument’s complexity. The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level. There were no transfers between fair value hierarchy
levels for the six months ended June 30, 2014.
Fair Value on a Recurring Basis
Derivative financial instruments are carried at fair value and measured on a recurring basis. The derivative financial instruments consist of swaps for crude oil and natural gas. The Company’s swaps are valued based on a discounted future cash flow model. The primary input for the model is published forward commodity price curves. The Company’s model is validated by the counterparty’s marked-to-market statements. The swaps are also designated as Level 2 within the valuation hierarchy.
The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of the Company’s nonperformance risk. The measurements are immaterial to the consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Fair Value on a Recurring Basis – Continued
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
- |
|
|
$ |
7,444 |
|
|
$ |
- |
|
|
$ |
7,444 |
|
Noncurrent derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
assets
|
|
|
- |
|
|
|
6,204 |
|
|
|
- |
|
|
|
6,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets
|
|
$ |
- |
|
|
$ |
13,648 |
|
|
$ |
- |
|
|
$ |
13,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liabilities
|
|
$ |
- |
|
|
$ |
1,273,321 |
|
|
$ |
- |
|
|
$ |
1,273,321 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial liabilities
|
|
$ |
- |
|
|
$ |
1,273,321 |
|
|
$ |
- |
|
|
$ |
1,273,321 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial assets
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
$ |
- |
|
|
$ |
154,310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative liabilities
|
|
$ |
- |
|
|
$ |
171,761 |
|
|
$ |
- |
|
|
$ |
171,761 |
|
Noncurrent derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
liabilities
|
|
|
- |
|
|
|
27,816 |
|
|
|
- |
|
|
|
27,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial liabilities
|
|
$ |
- |
|
|
$ |
199,577 |
|
|
$ |
- |
|
|
$ |
199,577 |
|
Other financial instruments include cash, accounts receivable and payable, and revenue royalties. The carrying amount of these instruments approximates fair value because of their short-term nature. The Company’s long-term debt obligation bears interest at floating market rates, therefore carrying amounts and fair value are approximately equal.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 5. FAIR VALUE MEASUREMENTS – CONTINUED
Fair Value on a Nonrecurring Basis
Oil and gas properties are measured at fair value on a nonrecurring basis. The impairment charge reduces the oil and gas properties’ carrying values to their estimated fair values. These fair value measurements are classified as Level 3 measurements and include many unobservable inputs. Fair value is calculated as the estimated discounted future net cash flows attributable to the assets. The Company’s primary assumptions in preparing the estimated discounted future net cash flows to be recovered from oil and gas properties are based on (i) proved reserves, (ii) forward commodity prices and assumptions as to costs and expenses, and (iii) the estimated discount rate that would be used by potential purchasers to determine the fair value of the assets. The Company did not
recognize any impairment write-downs with respect to its oil and gas properties during the three and six months ended June 30, 2014. The Company recognized asset impairments of $44,372 on unproved properties for both the three and six months ended June 30, 2013.
Business Combinations
The Company records the identifiable assets acquired and liabilities assumed at fair value at the date of acquisition on a nonrecurring basis. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on commodity futures price strips as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the determination of fair value of the acquisition include the Company’s estimate of future
natural gas and crude oil prices, operating and development costs, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. The Company’s acquisitions are discussed in Note 3 “Acquisitions and Divestitures”.
Asset Retirement Obligation
The asset retirement obligation estimates are derived from historical costs and management's expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. See Note 7, "Asset Retirement Obligations," for a reconciliation of the beginning and ending balances of the liability for the Company's asset retirement obligations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 6. LONG-TERM DEBT
On June 29, 2011, Oak Valley Energy, LLC (“OVE”) entered into a new four-year senior secured revolving credit facility (the “OVE Credit Facility”). The OVE Credit Facility was subsequently assumed by OVR on December 21, 2012, the date upon which all of the membership interests in OVE were assigned to OVR.
On July 10, 2013, the Company entered into an amended and restated credit agreement (the “OVR Credit Facility”) which matures on June 29, 2017. BOKF, NA dba Bank of Texas and Wells Fargo Bank, National Association serve as lenders. All of the obligations under the OVR Credit Facility are secured by substantially all of the Company’s assets. As of
June 30, 2014, the borrowing base was $44,500,000, outstanding borrowings totaled $10,825,000, and outstanding letters of credit totaled $300,000. As of December 31, 2013, the borrowing base was $44,500,000, outstanding borrowings totaled $10,825,000, and there were no outstanding letters of credit.
Outstanding borrowings under the OVR Credit Facility and the OVE Credit Facility, at the election of the Company, can bear interest at the LIBOR adjusted rate plus the applicable utilization margin of 2.25% to 4.25% (2.40% and 2.42% at June 30, 2014 and December 31, 2013, respectively) or at the base rate plus the applicable utilization-based margin of 1.00% to 3.00% (4.25% at June 30, 2014 and December 31, 2013, respectively). The Company pays a commitment rate of 0.500% on all unused borrowings.
The OVR Credit Facility contains a number of customary covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on asset, pay dividends, and repurchase its capital stock. In addition, the Company is required to maintain certain financial ratios, including a minimum current ratio of 1.0 to 1.0 and a maximum annualized quarterly leverage ratio of 4.0 to 1.0. As of June 30, 2014 and December 31, 2013, the Company was in compliance with respect to the financial covenants. Effective June
30, 2014, the OVR Credit Facility was amended to allow the Company to include unused aggregate commitments in the definition of current assets for the purposes of calculating the current ratio. The Company is also required to submit an audited annual report 120 days after the end of each fiscal period. For December 31, 2013, the Company received a waiver, which extended the deadline to provide an audited report to July 31, 2014.
Debt issuance costs of $550,206 and $524,023 associated with the Company’s credit facilities have been capitalized as of June 30, 2014 and December 31, 2013, respectively, and are amortized on a straight-line basis over the term of the credit agreement. Amortization expense was $37,785 and $14,656 for the three months ended June 30, 2014 and 2013, respectively, and $75,570 and $29,312 for the six months ended June 30, 2014 and 2013, respectively. Amortization expense is included in “Interest expense” on the Consolidated Statements of
Operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 7. ASSET RETIREMENT OBLIGATIONS
The Company has asset retirement obligations associated with the future plugging and abandonment of oil and gas properties and related facilities. The accretion of the asset retirement obligation is included in “Lease operating expense” in the Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives, and the discount rate.
The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of FASB ASC Topic 410, Asset Retirement and Environmental Obligations:
|
|
$ |
3,011,454 |
|
Liabilities settled
|
|
|
(31,120 |
) |
Liabilities incurred
|
|
|
28,558 |
|
Accretion expense
|
|
|
151,111 |
|
|
|
|
|
|
|
|
$ |
3,160,003 |
|
Based on expected timing of settlement, $66,625 and $69,956 of the asset retirement obligation is classified as current at June 30, 2014 and December 31, 2013, respectively.
NOTE 8. RELATED PARTY TRANSACTIONS
FASB ASC Topic 850, Related Party Disclosures (“ASC Topic 850”), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the financial statements can evaluate their significance. The following are significant related party transactions between the Company and Oak Valley Management (“OVM”) and certain Private Placement Investors for the three and six months ended June 30, 2014 and 2013, and as of June 30, 2014 and December 31, 2013. OVM members are management and employees of the
Company. Private Placement Investors participated in the private placement offering which raised capital commitments in exchange for equity in the Company.
The Company employs members of OVM. For the three months ended June 30, 2014 and 2013, the Company made payments totaling $745,875 and $525,961, respectively, to these members as compensation for services. For the six months ended June 30, 2014 and 2013, the Company made payments totaling $2,126,583 and $881,946, respectively, to these members as compensation for services. The payments are included in “General and administrative expense” on the Consolidated Statements
of Operations or has been charged out to oil and gas properties.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 8. RELATED PARTY TRANSACTIONS – CONTINUED
At December 31, 2013, the Company had a liability of $730,384 due to members of OVM, which is included in “Accrued expenses” on the Consolidated Balance Sheet. At June 30, 2014, the Company did not have a related party asset due from OVM members or a related party liability due to OVM members.
At June 30, 2014 and December 31, 2013, the Company had a liability of $403,661 and $627,586, respectively, due to companies to which certain Private Placement Investors are significant related parties, which is included in “Accounts payable” on Consolidated Balance Sheets.
NOTE 9. COMMITMENTS AND CONTINGENCIES
Gas Purchase and Gas Processing Contract
As a part of the Eagle Ford Acquisition discussed in Note 3 “Acquisitions and Divestitures”, the Company ratified several long-term gas purchasing and gas processing contracts. As is customary in the industry, the Company has reserved gathering and processing capacity in a pipeline. In one of the contracts, the Company has a volume commitment, whereby the Company pays the owner of the pipeline
a fee of $0.45 per MMBtu to hold 10,000 MMBtu per day of capacity for the Company’s use. Since the time of the acquisition, the Company has not been able to meet its delivery commitments. The rate and terms under this purchasing and processing contract expire on June 1, 2021.
Drilling Commitments
As of June 30, 2014, the Company had three drilling rigs under contract. Under the first drilling contract, the Company contractually agreed to drill five wells at a drilling day rate of approximately $19,200 per day. As of June 30, 2014, the Company drilled four wells and was in the process of drilling the fifth well. Early termination of the drilling rig contract
prior to drilling all five wells to total depth would require a termination payment of $145,000. Under the second drilling contract, the Company contractually agreed to drill five wells at a drilling day rate of approximately $22,600 and five more wells at a drilling day rate of approximately $26,100 for a total of ten wells. As of June 30, 2014, the Company completed drilling on four wells and drilling had not commenced on six wells. Early termination of the drilling rig contract prior to drilling all ten wells to total depth would require a termination payment of approximately
$500,000. Under the third contract, the Company entered into a six month drilling rig contract that commenced on May 24, 2014 and ends on November 24, 2014, at a drilling day rate of approximately $23,700 per day. As of June 30, 2014, termination of the contract subsequent to spudding of a well will require the Company to pay approximately $2,200,000.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 9. COMMITMENTS AND CONTINGENCIES – CONTINUED
Lease Commitments
On April 11, 2013, the Company entered into a three year lease agreement for office space in Houston, Texas, with an option to terminate the lease on July 31, 2014 and April 30, 2015, provided the Company gives the lessor six months’ notice. In January 2014, the Company gave written notice to the landlord to exercise the termination option and negotiated an extension of the first termination date. The Company’s lease will effectively terminate on November
30, 2014. As of June 30, 2014, the Company is contractually obligated under the office lease to make payments totaling $113,940 during 2014.
On September 19, 2013, the Company entered into a seven month lease agreement for office space in Denver, Colorado, with an entity controlled by the principals of VILLco Capital II, L.L.C. VILLco Capital II, L.L.C. is a related party. On March 10, 2014, the Company exercised the option to extend the lease until October 31, 2014. As of June 30, 2014, the Company is contractually obligated under the office lease to make payments totaling $6,428 during 2014.
On May 27, 2014, the Company entered into a 61 month lease agreement for office space in The Woodlands, Texas. The Company is contractually obligated under the office lease to make payments totaling $3,041,887. The lease will commence upon completion of a leasehold build out which is expected to be completed during the fourth quarter of 2014.
2014
|
|
$ |
169,378 |
|
2015
|
|
|
589,754 |
|
2016
|
|
|
599,556 |
|
2017
|
|
|
609,358 |
|
2018
|
|
|
619,160 |
|
Thereafter
|
|
|
575,049 |
|
|
|
|
|
|
|
|
$ |
3,162,255 |
|
Rent expense under non-cancellable operating leases was $73,049 and $13,140 for the three months ended June 30, 2014 and 2013, respectively. Rent expense under non-cancellable operating leases was $140,413 and $51,345 for the six months ended June 30, 2014 and 2013, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 9. COMMITMENTS AND CONTINGENCIES – CONTINUED
Contingencies
In the course of its business affairs and operations, the Company is subject to possible loss contingencies arising from federal, state, and local environmental, health and safety laws and regulations and third party litigation. The Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the
Company’s unaudited condensed consolidated operating results, financial position or cash flows.
NOTE 10. SUBSEQUENT EVENTS
In July 2014, the Company completed one of the drilling commitments discussed in Note 9, “Commitments and Contingencies” by drilling all five wells to total depth. After completing the drilling commitment,
the Company released the drilling rig.
Statements of Revenues and Direct Operating Expenses of the Oak Valley Resources, LLC Acquisition Properties as of and for the Years Ended December 31, 2012 and 2011 (Audited) and as of and for the Six Months Ended June 30, 2013 and 2012 (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Board of Managers of
Oak Valley Resources, LLC
We have audited the accompanying statements of revenues and direct operating expenses of the Oak Valley Resources Acquisition Properties for the years ended December 31, 2012 and 2011. These financial statements are the responsibility of the Oak Valley Resources, LLC management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Oak Valley Resources Acquisition Properties described in Note 1 for the years ended December 31, 2012 and 2011, in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements reflect the revenues and direct operating expenses of the Oak Valley Resources Acquisition Properties as described in Note 1 and are not intended to be a complete presentation of the financial position, results of operations, or cash flows of the Oak Valley Resources Acquisition Properties.
Houston, Texas
OAK VALLEY RESOURCES ACQUISTION PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
|
|
Six Months Ended
|
|
|
Year Ended
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
2012
|
|
|
2011
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
$ |
16,438,465 |
|
|
$ |
5,554,411 |
|
|
$ |
17,025,741 |
|
|
$ |
1,832,008 |
|
Natural gas and natural gas liquids
|
|
|
429,007 |
|
|
|
50,607 |
|
|
|
483,121 |
|
|
|
23,177 |
|
|
|
|
16,867,472 |
|
|
|
5,605,018 |
|
|
|
17,508,862 |
|
|
|
1,855,185 |
|
Direct operating expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
|
1,436,979 |
|
|
|
256,736 |
|
|
|
1,070,376 |
|
|
|
201,167 |
|
Severance taxes
|
|
|
786,934 |
|
|
|
259,815 |
|
|
|
819,405 |
|
|
|
85,953 |
|
Re-engineering and workovers
|
|
|
49,533 |
|
|
|
749 |
|
|
|
58,674 |
|
|
|
3,622 |
|
Exploration expense
|
|
|
389,610 |
|
|
|
- |
|
|
|
- |
|
|
|
434,888 |
|
|
|
|
2,663,056 |
|
|
|
517,300 |
|
|
|
1,948,455 |
|
|
|
725,630 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$ |
14,204,416 |
|
|
$ |
5,087,718 |
|
|
$ |
15,560,407 |
|
|
$ |
1,129,555 |
|
See notes to statements of revenues and direct operating expenses
Oak Valley Resources Acquisition Properties
Notes to Statements of Revenues and Direct Operating Expenses
Note 1—Properties and Basis of Presentation
The accompanying statements represent the interests in the revenues and direct operating expenses of the oil and natural gas producing properties acquired by Oak Valley Resources, LLC (“Oak Valley”) on July 19, 2013 from Halcon Resources Corporation and Ramshorn Investments, Inc., and August 19, 2013 from CEU Eagle Ford, LLC and Trigon Energy Management, LLC (collectively “the Sellers”) effective January 1, 2013. Oak Valley paid $87.7 million for the properties, after closing adjustments for normal operational activity and other purchase price adjustments that occurred between the effective date of the acquisition and the closing date of the acquisition. The properties are referred to herein as the “Oak Valley Resources Acquisition Properties” and are located in the Fayette
and Gonzales counties in Texas.
The statements of revenues and direct operating expenses have been derived from Halcon Resources Corporation’s historical financial records and prepared on the accrual basis of accounting. Revenues and direct operating expenses relate to the historical net revenue interests and net working interests acquired by Oak Valley. Oil, natural gas and natural gas liquids revenues are recognized on the sales method when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease operating expenses, production and ad valorem taxes, transportation and all other direct operating costs associated with the properties. Direct operating expenses do not include corporate overhead, interest expense and income taxes.
The statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the Oak Valley Resources Acquisition Properties going forward due to the omission of various operating expenses. During the periods presented, the Oak Valley Resources Acquisition Properties were not accounted for by Oak Valley as a separate business unit. As such, certain costs, such as depreciation, depletion and amortization of oil and gas properties, accretion of asset retirement obligations, general and administrative expenses, interest expense and income taxes were not allocated to the Oak Valley Resources Acquisition Properties.
The preparation of statements of revenues and direct operating expenses in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting periods. Although these estimates are based on management’s best available knowledge of current and future events, actual results could be different from those estimates.
Note 2—Omitted Financial Information
Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on a property-by-property basis, nor is it practicable to obtain such information in these circumstances. Historically, no allocation of general and administrative, interest expense, corporate taxes, accretion of asset retirement obligations, and depreciation, depletion and amortization of oil and gas properties was made to the Oak Valley Resources Acquisition Properties. Accordingly, the statements of revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-01 and Rule 3-02 of the Securities and Exchange Commission’s Regulation S-X.
Oak Valley Resources Acquisition Properties
Notes to Statements of Revenues and Direct Operating Expenses
Oil and Gas Reserve Information
The following tables summarize the net ownership interests in estimated quantities of proved, proved developed and proved undeveloped (“PUD”) oil and natural gas reserves of the Oak Valley Resources Acquisition Properties for the periods indicated, estimated by Oak Valley’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the periods indicated. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Supplemental Oil and Gas Reserve Information (Unaudited)
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
and Natural
|
|
|
|
|
|
|
Oil
|
|
|
Gas Liquids
|
|
|
Total
|
|
|
|
(Bbl)
|
|
|
(Mcf)
|
|
|
(BOE) (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extension and discoveries
|
|
|
799,908 |
|
|
|
585,818 |
|
|
|
897,544 |
|
Production
|
|
|
(21,601 |
) |
|
|
(4,412 |
) |
|
|
(22,336 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
778,307 |
|
|
|
581,406 |
|
|
|
875,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extension and discoveries
|
|
|
2,813,173 |
|
|
|
2,100,904 |
|
|
|
3,163,324 |
|
Production
|
|
|
(174,320 |
) |
|
|
(95,864 |
) |
|
|
(190,297 |
) |
Revision to previous estimates
|
|
|
(114,220 |
) |
|
|
(126,843 |
) |
|
|
(135,361 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,302,940 |
|
|
|
2,459,603 |
|
|
|
3,712,874 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
307,707 |
|
|
|
263,817 |
|
|
|
351,676 |
|
|
|
|
1,467,236 |
|
|
|
1,175,955 |
|
|
|
1,663,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
470,600 |
|
|
|
317,589 |
|
|
|
523,532 |
|
|
|
|
1,835,704 |
|
|
|
1,283,648 |
|
|
|
2,049,645 |
|
(1) Barrel of oil equivalent (BOE); assume a ratio of 6 Mcf of natural gas per barrel of oil
In 2012, the revision decrease in estimated oil, natural gas and natural gas liquids was 135,361 BOE; this downward revision resulted from removal of several PUD wells that were determined to be uneconomic based on well performance data from offsetting wells.
Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Oak Valley Resources Acquisition Properties
Notes to Statements of Revenues and Direct Operating Expenses
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves.
The following table sets forth the computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows of the Oak Valley Resources Acquisition Properties in accordance with ASC 932, Extractive Activities—Oil and Gas and based on oil and natural gas reserve and production volumes. Future cash inflows as of December 31, 2012 and 2011 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month oil and gas prices for each month within the 12-month period ended December 31, 2012 and 2011) to estimated future production. Future production
and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on year-end costs and assuming the continuation of existing economic conditions. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the ASC 932, a discount rate of 10% is applied to the annual future net cash flows.
In calculating the Standardized Measure, future net cash inflows were estimated by using the unweighted arithmetic average of first-day-of-the-month oil and gas prices for the period with the estimated future production of period-end proved reserves and assume continuation of existing economic conditions. These prices were $94.71 per barrel of oil and $2.75 per MMBtu of natural gas at December 31, 2012 and $96.19 per barrel of oil and $4.12 per MMBtu of natural gas at December 31, 2011. The index prices have been adjusted for historical average location and quality differentials. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs resulting in net cash flow before tax. Future income tax expense was not considered as Oak Valley and the Oak Valley Resources Acquisition
Properties are not tax-paying entities.
The Standardized Measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.
Oak Valley Resources Acquisition Properties
Notes to Statements of Revenues and Direct Operating Expenses
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$ |
353,596,875 |
|
|
$ |
84,674,448 |
|
Future production costs
|
|
|
(77,346,202 |
) |
|
|
(18,415,214 |
) |
Future development costs
|
|
|
(71,646,525 |
) |
|
|
(20,988,751 |
) |
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
204,604,148 |
|
|
|
45,270,483 |
|
|
|
|
|
|
|
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(106,979,601 |
) |
|
|
(24,541,744 |
) |
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future cash flows
|
|
$ |
97,624,547 |
|
|
$ |
20,728,739 |
|
Changes in the Standardized Measure are as follows:
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
|
|
Beginning of the year
|
|
$ |
20,728,739 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(15,560,407 |
) |
|
|
(1,564,443 |
) |
Net changes in prices and production costs
|
|
|
81,570 |
|
|
|
- |
|
Extensions, discoveries and improved recoveries
|
|
|
79,062,270 |
|
|
|
22,293,182 |
|
Previously estimated development cost incurred during the period
|
|
|
8,400,000 |
|
|
|
- |
|
Revision of previous quantity estimates
|
|
|
(3,205,888 |
) |
|
|
- |
|
Accretion of discount
|
|
|
2,072,874 |
|
|
|
- |
|
Changes in timing of estimated cash flows and others
|
|
|
6,045,389 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
End of the year
|
|
$ |
97,624,547 |
|
|
$ |
20,728,739 |
|
FINANCIAL STATEMENTS OF EARTHSTONE ENERGY, INC.
Audited Financial Statements of Earthstone Energy, Inc. as of and for the Years Ended March 31, 2014 and 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Earthstone Energy, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Earthstone Energy, Inc. and Subsidiaries (the “Company”) as of March 31, 2014 and 2013, and the related statements of operations, shareholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Earthstone Energy, Inc. as of March 31, 2014 and 2013, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
Denver, Colorado
Consolidated Balance Sheets
Page 1 of 2
|
|
March 31,
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Assets
|
Current assets:
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,671,000
|
|
|
$
|
2,180,000
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
3,895,000
|
|
|
|
2,753,000
|
|
Joint interest and other receivables, net of allowance of ($15,000) and ($38,000), respectively
|
|
|
758,000
|
|
|
|
630,000
|
|
Other current assets
|
|
|
1,043,000
|
|
|
|
814,000
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
8,367,000
|
|
|
|
6,377,000
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
67,186,000
|
|
|
|
53,265,000
|
|
Unproved properties
|
|
|
773,000
|
|
|
|
2,156,000
|
|
Accumulated depletion and impairment
|
|
|
(31,496,000
|
)
|
|
|
(27,729,000
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
36,463,000
|
|
|
|
27,692,000
|
|
|
|
|
|
|
|
|
|
|
Support equipment and other non-current assets, net of accumulated depreciation of ($514,000) and ($416,000), respectively
|
|
|
791,000
|
|
|
|
611,000
|
|
|
|
|
|
|
|
|
|
|
Total non-current assets
|
|
|
37,254,000
|
|
|
|
28,303,000
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
45,621,000
|
|
|
$
|
34,680,000
|
|
See accompanying notes to consolidated financial statements
Earthstone Energy, Inc.
Consolidated Balance Sheets
Page 2 of 2
|
|
March 31,
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Liabilities and Shareholders’ Equity
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
430,000
|
|
|
$
|
1,631,000
|
|
Accrued liabilities
|
|
|
5,243,000
|
|
|
|
3,971,000
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
5,673,000
|
|
|
|
5,602,000
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
9,000,000
|
|
|
|
4,000,000
|
|
Deferred tax liability
|
|
|
4,486,000
|
|
|
|
2,971,000
|
|
Asset retirement obligation, less current portion
|
|
|
2,068,000
|
|
|
|
1,809,000
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
15,554,000
|
|
|
|
8,780,000
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
21,227,000
|
|
|
|
14,382,000
|
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
|
|
Preferred shares, $0.001 par value, 600,000 authorized and none issued or outstanding
|
|
|
-
|
|
|
|
-
|
|
Common shares, $0.001 par value, 6,400,000 shares authorized and 1,753,000 and 1,802,000 shares issued, respectively
|
|
|
18,000
|
|
|
|
18,000
|
|
Additional paid-in capital
|
|
|
23,436,000
|
|
|
|
23,278,000
|
|
Treasury stock, at cost, 24,000 and 82,000 shares, respectively
|
|
|
(458,000
|
)
|
|
|
(457,000
|
)
|
Accumulated earnings (deficit)
|
|
|
1,398,000
|
|
|
|
(2,541,000
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders’ equity
|
|
|
24,394,000
|
|
|
|
20,298,000
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders’ equity
|
|
$
|
45,621,000
|
|
|
$
|
34,680,000
|
|
See accompanying notes to consolidated financial statements
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
2013
|
|
Revenues:
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
17,440,000
|
|
|
$
|
10,982,000
|
|
Well service and water-disposal revenue
|
|
|
74,000
|
|
|
|
396,000
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
17,514,000
|
|
|
|
11,378,000
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
3,957,000
|
|
|
|
3,453,000
|
|
Production tax
|
|
|
1,582,000
|
|
|
|
971,000
|
|
Well service and water-disposal
|
|
|
100,000
|
|
|
|
94,000
|
|
Depletion and depreciation
|
|
|
3,881,000
|
|
|
|
2,017,000
|
|
Accretion of asset retirement obligation
|
|
|
202,000
|
|
|
|
177,000
|
|
General and administrative
|
|
|
2,628,000
|
|
|
|
2,625,000
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
12,350,000
|
|
|
|
9,337,000
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
5,164,000
|
|
|
|
2,041,000
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
73,000
|
|
|
|
62,000
|
|
Interest and other expenses
|
|
|
(173,000
|
)
|
|
|
(21,000
|
)
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(100,000
|
)
|
|
|
41,000
|
|
|
|
|
|
|
|
|
|
|
Income before income tax
|
|
|
5,064,000
|
|
|
|
2,082,000
|
|
|
|
|
|
|
|
|
|
|
Current income tax (benefit) expense
|
|
|
(390,000
|
)
|
|
|
62,000
|
|
Deferred income tax expense
|
|
|
1,515,000
|
|
|
|
240,000
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
|
1,125,000
|
|
|
|
302,000
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
3,939,000
|
|
|
$
|
1,780,000
|
|
|
|
|
|
|
|
|
|
|
Per share amounts:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
2.27
|
|
|
$
|
1.03
|
|
Diluted
|
|
$
|
2.27
|
|
|
$
|
1.03
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1,731,812
|
|
|
|
1,720,712
|
|
Diluted
|
|
|
1,731,812
|
|
|
|
1,720,712
|
|
See accompanying notes to consolidated financial statements
Consolidated Statements of Shareholders’ Equity
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
Common shares
|
|
|
paid-in
|
|
|
Treasury shares
|
|
|
earnings/
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
capital
|
|
|
Shares
|
|
|
Amount
|
|
|
(deficit)
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,788,000
|
|
|
$
|
18,000
|
|
|
$
|
23,108,000
|
|
|
|
(82,000
|
)
|
|
$
|
(457,000
|
)
|
|
$
|
(4,321,000
|
)
|
|
$
|
18,348,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
14,000
|
|
|
|
-
|
|
|
|
170,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
170,000
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,780,000
|
|
|
|
1,780,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,802,000
|
|
|
$
|
18,000
|
|
|
$
|
23,278,000
|
|
|
|
(82,000
|
)
|
|
$
|
(457,000
|
)
|
|
$
|
(2,541,000
|
)
|
|
$
|
20,298,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of treasury shares
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,000
|
)
|
|
|
-
|
|
|
|
(1,000
|
)
|
Share-based compensation
|
|
|
12,000
|
|
|
|
-
|
|
|
|
158,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
158,000
|
|
Reclassification of shares held in treasury
|
|
|
(58,000
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
58,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Forfeitures
|
|
|
(3,000
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,939,000
|
|
|
|
3,939,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,753,000
|
|
|
$
|
18,000
|
|
|
$
|
23,436,000
|
|
|
|
(24,000
|
)
|
|
$
|
(458,000
|
)
|
|
$
|
1,398,000
|
|
|
$
|
24,394,000
|
|
See accompanying notes to consolidated financial statements
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
2013
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
Net income
|
|
$
|
3,939,000
|
|
|
$
|
1,780,000
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
3,881,000
|
|
|
|
2,017,000
|
|
Deferred income tax expense
|
|
|
1,515,000
|
|
|
|
240,000
|
|
Accretion of asset retirement obligation
|
|
|
202,000
|
|
|
|
177,000
|
|
Share-based compensation
|
|
|
158,000
|
|
|
|
170,000
|
|
Amortization of deferred financing costs
|
|
|
13,000
|
|
|
|
2,000
|
|
Change in:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,270,000
|
)
|
|
|
(904,000
|
)
|
Other current assets
|
|
|
(501,000
|
)
|
|
|
(74,000
|
)
|
Accounts payable and accrued liabilities
|
|
|
(1,496,000
|
)
|
|
|
459,000
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
6,441,000
|
|
|
|
3,867,000
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
(10,934,000
|
)
|
|
|
(12,243,000
|
)
|
Proceeds from sale of oil and gas property and equipment
|
|
|
292,000
|
|
|
|
-
|
|
Purchases of support equipment and other non-current assets
|
|
|
(261,000
|
)
|
|
|
(174,000
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(10,903,000
|
)
|
|
|
(12,417,000
|
)
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Borrowings on long-term debt
|
|
|
5,000,000
|
|
|
|
4,000,000
|
|
Deferred financing costs
|
|
|
(46,000
|
)
|
|
|
(48,000
|
)
|
Purchase of treasury shares
|
|
|
(1,000
|
)
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
4,953,000
|
|
|
|
3,952,000
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents:
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
491,000
|
|
|
|
(4,598,000
|
)
|
Cash and cash equivalents, beginning of year
|
|
|
2,180,000
|
|
|
|
6,778,000
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$
|
2,671,000
|
|
|
$
|
2,180,000
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
154,000
|
|
|
$
|
15,000
|
|
Cash paid for income tax
|
|
$
|
1,000
|
|
|
$
|
341,000
|
|
Non-cash:
|
|
|
|
|
|
|
|
|
Increase in oil and gas property due to asset retirement obligation
|
|
$
|
85,000
|
|
|
$
|
102,000
|
|
Accrued capital expenditures
|
|
$
|
1,539,000
|
|
|
$
|
1,546,000
|
|
Prepaid capital expenditures
|
|
$
|
272,000
|
|
|
$
|
9,000
|
|
See accompanying notes to consolidated financial statements
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Organization and Nature of Operations. Earthstone Energy, Inc. (the “Company”) was originally organized in July 1969 as Basic Earth Science Systems, Inc. and changed its name in 2010 to Earthstone Energy, Inc. The Company is principally engaged in the acquisition, exploration, development, and production of crude oil and natural gas properties, primarily operating in the North Dakota and Montana portions of the Williston Basin and South Texas.
On May 15, 2014 the Company and Oak Valley, entered into an Exchange Agreement. The Exchange Agreement provides that, upon the terms and subject to the conditions set forth in the Exchange Agreement, Oak Valley will contribute to the Company the membership interests of its three subsidiaries, each a Texas limited liability company, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, in exchange for the issuance of approximately 9.1 million shares of the Company’s common stock. Following the Exchange, current
Earthstone stockholders will own 16% of the Company’s outstanding Common Stock and Oak Valley will own 84% of the Company’s outstanding Common Stock. The Exchange Agreement has been approved by the board of directors of Earthstone and the board of managers of Oak Valley. See Note 12 below for further information.
Principles of Consolidation. The consolidated financial statements include the accounts of Earthstone Energy, Inc. and its wholly-owned subsidiary. All significant intercompany accounts and transactions have been eliminated. The Company does not have any unconsolidated special purpose entities.
At the directive of the U.S. Securities and Exchange Commission (“SEC”) to use “plain English” in public filings, the Company uses such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the audited consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board, corporate officers, management, or any individual employee or group of employees.
Basis of Presentation. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
Oil and Gas Sales. The Company derives revenue primarily from the sale of produced natural gas and crude oil. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company’s interest. Revenues are reported on a gross basis for the amounts received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded and receivables are accrued using the sales method, which occurs in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment
is generally received between 30 and 90 days after the date of production. Collection of the revenue may vary depending on the status of wells or the performance of the operator. Estimates of the amount of production delivered to purchasers and the prices at which it was delivered are necessary at year end. Management’s knowledge of the Company’s properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices, and other factors are the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received, or when better information is available.
Oil and Gas Reserves. Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
Oil and Gas Property. The Company uses the full cost method of accounting for costs related to its oil and gas property. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition and exploration activities.
Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
Capitalized costs are subject to a ceiling test, as prescribed by SEC regulations, that limits such pooled costs to the aggregate of the present value of future net cash flows attributable to proved oil and gas reserves, less future cash outflows associated with the asset retirement obligation that have been accrued plus the lower of cost or estimated fair value of unproved properties not being amortized less any associated tax effects. Prices are held constant for the productive life of each well. If the full cost pool of capitalized oil and gas property costs exceeds the ceiling, the excess is reflected as a non-cash charge to earnings. The write-down is permanent and not reversible in future periods, even though higher oil and gas prices in the future may subsequently and significantly increase the ceiling amount. As of the balance sheet date, capitalized costs did not exceed the ceiling test limit.
For the years ended March 31, 2014 and 2013, the oil and natural gas prices used to calculate the full cost ceiling limitation are the 12-month average prices, calculated as the unweighted arithmetic average price of oil and gas on the first day of each month for each of the 12 months prior to the last day of the reporting period (unless prices are defined by contractual arrangements) and net cash flows are discounted at ten percent.
Unproved properties are excluded from the ceiling test. Instead, these property costs are periodically reviewed for impairment by reviewing the status of the activity on those properties and surrounding properties either held by the Company or other parties.
Capitalized costs of oil and gas properties, excluding those pertaining to unproved properties, are depleted on a composite units-of-production method based on estimated proved reserves. For depletion purposes, the volume of reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.
Oil and Gas Production Costs. Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Production costs (also referred to as lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities, and severance taxes.
Asset Retirement Obligation. The Company’s activities are subject to various laws and regulations, including legal and contractual obligation to plug, reclaim, remediate, or otherwise restore oil and gas property at the time such asset ceases to be productive. An asset retirement obligation (“ARO”) is initially measured at fair value and recorded as a liability with a corresponding asset when incurred if a reasonable estimate of fair value can be made. This is typically when a well is spud or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the full cost pool. Over time, the liability increases for the change in its present value (and accretion
expense is recorded), while the capitalized cost decreases by way of depletion of the full cost pool. Estimates are reviewed quarterly and adjusted in the period in which new information results in a change of estimate.
Income Tax. Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.
No uncertain tax positions were identified as of any date on or before March 31, 2014. The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of March 31, 2014, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 9 below for further information.
Earnings Per Share. Basic and diluted earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Included in our basic and diluted earnings per share calculations are the unvested common shares issued to employees and directors of the Company. Inclusion of the unvested common shares in basic and diluted earnings per share has not resulted in a material variance between basic and diluted earnings per share.
Cash and Cash Equivalents. All highly liquid investments with original maturities of 90 days or less are considered to be cash equivalents. During the period and at the balance sheet date, balances of cash and cash equivalents exceeded the federally insured limit.
Fair Value Measurements. Financial instruments and nonfinancial assets and liabilities, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables and accrued liabilities, and long-term debt, all of which are considered to be representative of their fair market value, due to the short-term and highly liquid nature of these instruments.
As discussed in Note 6, the Company incurred asset retirement obligations of $85,000 for the year ended March 31, 2014 and asset retirement obligations of $69,000 and an additional $33,000 related to revisions in estimated liabilities for the year ended March 31, 2013, the value of which was determined using unobservable pricing inputs (or Level 3 inputs). The Company uses the income valuation technique to estimate the fair value of the obligation using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement.
Hedging Activities. The Company had no hedging activities in the years ended March 31, 2014 and 2013. Hedging strategies, or absence of hedging, may vary or change due to change of circumstances, unforeseen opportunities, inability to fund margin requirements, lending institution requirements and other events which the Company is not able to anticipate.
Support Equipment. Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years.
Inventory. Inventory, consisting primarily of tubular goods and oil field equipment to be used in future drilling operations or repair operations, is stated at the lower of cost or market, cost being determined by the FIFO method.
Commitments. The Company is committed to $9,880 per month plus maintenance fees on a 7,000 square foot office space located in downtown Denver, Colorado. The lease term ends on April 30, 2016. The Company does not have any off-balance sheet financing transactions, arrangements or obligations.
Major Customers and Operating Region. The Company operates exclusively within the United States of America. All of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry. Individual external purchasers of 10% or more of the Company’s oil and gas production revenue for the years ended March 31, 2014 and 2013 were as follows:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Valero Energy Corp.
|
|
|
11
|
%
|
|
|
17
|
%
|
Plains Marketing LP
|
|
|
6
|
%
|
|
|
10
|
%
|
Total
|
|
|
17
|
%
|
|
|
27
|
%
|
For the years ended March 31, 2014 and 2013, approximately 80% and 65%, respectively, of Earthstone’s oil and gas revenue was from non-operated properties where the Company has no direct contact with the actual purchaser. On these properties, Earthstone’s portion of the product was marketed by the 25 different companies who operate these wells. These 25 companies may, unbeknownst to the Company, market to one or more of the same purchasers to whom the Company sells directly. Therefore, the Company
is unable to ascertain the total extent of combined purchaser concentration. It is not expected that the loss of any one of these purchasers would cause a material adverse impact on the Company’s results from operations, as alternative markets for oil and gas production are readily available.
Bad Debt Expense. A charge is recognized in general and administrative expenses and an allowance is established against specific receivable balances from joint interest owners in instances where working interest owners’ dispute amounts billed for their proportionate share in the cost of wells which the Company operates. As individual disputes are resolved, either the expense is reversed in the period of the resolution or the receivable is written down.
Share-Based Compensation. The Company recognizes all equity-based compensation as share-based compensation expense, included in general and administrative expenses, based on the fair value of the compensation measured at the grant date. The expense is recognized over the vesting period of the grant. See Note 8 below for information.
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.
Reclassifications. Certain prior year amounts were reclassified to conform to current presentation. Such reclassifications had no effect on the prior year net income, accumulated deficit, net assets or total shareholders’ equity.
Recent Accounting Pronouncements. In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company was required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.
In July 2013, the FASB issued ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for the Company’s fiscal quarter ending June 30, 2014. ASU 2013-11 impacts
balance sheet presentation only. The Company is currently evaluating the impact of the new rule but believes the balance sheet impact will not be material.
Various other accounting pronouncements have been recently issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, and are not expected to have a material effect on the Company’s financial position, results of operations, or cash flows.
2. Other Current Assets
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Prepaid income tax
|
|
$
|
379,000
|
|
|
$
|
112,000
|
|
Lease and well equipment inventory
|
|
|
310,000
|
|
|
|
371,000
|
|
Drilling and completion cost prepayments
|
|
|
223,000
|
|
|
|
210,000
|
|
Prepaid insurance premiums
|
|
|
91,000
|
|
|
|
88,000
|
|
Other current assets
|
|
|
40,000
|
|
|
|
33,000
|
|
|
|
|
|
|
|
|
|
|
Total other current assets
|
|
$
|
1,043,000
|
|
|
$
|
814,000
|
|
Lease and well equipment inventory included in other current assets represents well site production equipment owned by the Company that has been removed from wells that the Company operates. This occurs when the Company plugs a well or replaces defective, damaged or suspect equipment on a producing well. In this case, salvaged equipment is valued at prevailing market prices, removed from the full cost pool and made available for sale. This equipment is carried on the balance sheet at a value not to exceed the original carrying value established at the time it was placed in inventory. This equipment is intended for resale to third parties at current fair market prices. Sale of
this equipment is expected to occur in less than one year. This policy does not preclude the Company from further transferring serviceable equipment to other wells that the Company operates, on an as needed basis. During the year, the Company impaired approximately $61,000 of inventory to production expense.
Drilling and completion cost prepayments represent cash expenditures advanced by the Company to outside operators prior to the commencement of drilling and/or completion operations on a well.
3. Other Non-Current Assets
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Support equipment and lease and well equipment inventory
|
|
$
|
590,000
|
|
|
$
|
500,000
|
|
Plugging bonds
|
|
|
122,000
|
|
|
|
65,000
|
|
Deferred financing costs
|
|
|
79,000
|
|
|
|
46,000
|
|
|
|
|
|
|
|
|
|
|
Total other non-current assets
|
|
$
|
791,000
|
|
|
$
|
611,000
|
|
Support equipment represents non-oil and gas property (including such items as vehicles, office furniture and equipment and well servicing equipment) and is stated at the lower of cost or market. Depreciation of support equipment was $114,000 and $66,000 for the years ended March 31, 2014 and 2013, respectively, which was computed using primarily the straight-line method over periods ranging from five to seven years.
Non-current lease and well equipment inventory, unlike the equipment inventory in other current assets that is held for resale, is intended for use on leases that the Company operates. This equipment inventory represents well site production equipment that the Company owns that has either been purchased or has been removed from wells that the Company operates. When placed in inventory, new equipment is valued at cost and salvaged equipment is valued at prevailing market prices. The inventory is carried at the lower of the original carrying value or fair market value.
Plugging bonds represent Certificates of Deposit furnished by the Company to third parties who supply plugging bonds to federal and state agencies where the Company operates wells.
Deferred financing costs represent fees and expenses incurred in connection with the origination of the Company’s credit facility in December 2012. These costs will be amortized on a straight-line basis over the five year term of the facility.
4. Accrued Liabilities
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Accrued operations payable
|
|
$
|
4,209,000
|
|
|
$
|
2,933,000
|
|
Accrued compensation
|
|
|
411,000
|
|
|
|
429,000
|
|
Short-term asset retirement obligation
|
|
|
317,000
|
|
|
|
296,000
|
|
Accrued income tax payable and other
|
|
|
180,000
|
|
|
|
213,000
|
|
Revenue and production taxes payable
|
|
|
126,000
|
|
|
|
100,000
|
|
|
|
|
|
|
|
|
|
|
Total accrued liabilities
|
|
$
|
5,243,000
|
|
|
$
|
3,971,000
|
|
5. Long-Term Debt
On December 21, 2012 the Company entered into a $25 million senior secured revolving bank credit facility (the “Credit Facility”) with the Bank of Oklahoma (the “Bank”). The initial borrowing base on the Credit Facility was $6 million. The maturity date of the Credit Facility is December 21, 2017 and provides for a borrowing base subject to redetermination semi-annually each June and December and for certain unscheduled redeterminations. The Credit Facility is secured by mortgages on primarily all of the Company’s properties and an assignment of all the proceeds from severed and extracted hydrocarbons from the properties described in the mortgages. Until
further notice, the Bank has suspended their right to receive the proceeds directly.
Effective September 10, 2013, the Company entered into a Waiver and First Amendment to Credit Agreement (the “Amended Credit Facility”) with the Bank in connection with a semiannual redetermination of the borrowing base. The redetermination resulted in an increase in the borrowing base from $6 million under the initial Credit Facility to $12 million under the Amended Credit Facility, which amount is subject to redetermination. The Company’s ability to remain in compliance with the financial covenants may be affected by events and other factors beyond the Company’s control, including market prices for the
Company’s oil and gas and the rate at which the operators of projects drill in which the Company participates. Any future inability to comply with these covenants, unless waived by the Bank, could adversely affect the Company’s liquidity by rendering the Company unable to borrow further under the Amended Credit Facility.
The Credit Facility contains negative covenants that limit the Company’s ability, among other things, to pay any cash dividends, incur additional indebtedness, sell assets, enter into hedging contracts, change the nature of its business or operations, merge, consolidate or make investments. In addition, the Company is required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. As of March 31, 2014, the Company
was in compliance with all of the financial covenants under the Credit Facility. Should our Exchange Agreement with Oak Valley close we would require the consent of the Bank.
Payments of interest are due quarterly in arrears at prime plus 0.75% to 1.75% or LIBOR plus 1.75% to 2.75%, depending on the Company’s level of borrowing and election at the date of borrowing. Commitment fees on the unused amounts of the Credit Facility are due quarterly at rates from 0.35% to 0.50% on the unused amounts of the Credit Facility. At closing, the Company paid a borrowing base fee of $30,000, or 0.5%, on the $6 million borrowing base. An additional borrowing base fee of $30,000, or 5%, on the increase in borrowing base of $6 million under the Amended Credit Facility was paid by the Company during the year ended March
31, 2014. These costs have been recorded as deferred financing costs and will be amortized over the term of the facility. Deferred financing fees in the amount of $34,000 related to legal expenses and other costs to originate the Credit Facility and the Amended Credit Facility have been recorded. These costs will be amortized over the term on the facility. Amortization of deferred financing fees in the amount of $13,000 was recorded during the year ended March 31, 2014. Additional borrowing base fees may be payable upon future increases in the borrowing base, if any. As of March 31, 2014, the Company had an outstanding balance under the Credit Facility of $9 million.
6. Asset Retirement Obligation
For the purpose of determining the fair value of the asset retirement obligation incurred during the year ended March 31, 2014, the Company assumed an inflation rate of 4.07%, an estimated average asset life of 30 years, and a credit adjusted risk free interest rate of 7.85%.
The following reconciles the value of the asset retirement obligation for the periods presented. This included a short-term obligation of $317,000 and $296,000 as of March 31, 2014 and 2013, respectively, which was a component of accrued liabilities on the balance sheets:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Asset retirement obligation, beginning of year
|
|
$
|
2,105,000
|
|
|
$
|
1,826,000
|
|
Liabilities settled
|
|
|
(7,000
|
)
|
|
|
-
|
|
Liabilities incurred
|
|
|
85,000
|
|
|
|
69,000
|
|
Revisions in estimated liabilities
|
|
|
-
|
|
|
|
33,000
|
|
Accretion
|
|
|
202,000
|
|
|
|
177,000
|
|
Asset retirement obligation, end of year
|
|
|
2,385,000
|
|
|
|
2,105,000
|
|
|
|
|
|
|
|
|
|
|
Less Current portion
|
|
|
(317,000
|
)
|
|
|
(296,000
|
)
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, less current portion
|
|
$
|
2,068,000
|
|
|
$
|
1,809,000
|
|
7. Commitments
Office rent expense was approximately $202,000 and $158,000 for the years ended March 31, 2014 and 2013, respectively (including building maintenance charges). The Company is committed to a total of $247,000 for the remaining term on its 7,000 square foot office space located in downtown Denver, Colorado, ending April 30, 2016.
8. Shareholders’ Equity
Preferred Shares. The Company has 600,000 shares of authorized preferred stock with a par value of $0.001 available for issuance in such series and preferences as determined by the Board. Since inception, the Company has not issued any preferred shares.
Common Shares. The Company has authorized 6,400,000 shares of common stock with a par value of $0.001. The total issued common stock as of March 31, 2014, was 1,753,000 common shares.
Share-Based Compensation. On March 8, 2007, the Board adopted a Director Compensation Plan (“the Plan”) allotting up to 50,728 shares of the Company’s common stock to be issued to independent, non-employee directors. In connection with the Plan, an annual stock grant equal to $36,000 is awarded to each independent director. The number of shares included in each grant is calculated based upon the average closing price of the ten trading days preceding each April 1st anniversary date. Shares are subject to certain restrictions and vesting.
During the year ended March 31, 2014, 6,525 shares of common stock reserved for issuance under the Plan were authorized for issuance. Accordingly, as of March 31, 2014, 3,661 shares of common stock remain available for issuance under the Plan. Grants of shares of restricted stock vest one-third each year over three years. In accordance with the terms of the Plan, if a director’s participation as a member of the Board ceases or is terminated for any reason prior to the date the shares of restricted stock are fully vested, the unvested portion of the restricted stock shall be automatically forfeited and shall revert back to the Company. The aggregate number of restricted stock awards outstanding and subject to vesting at March 31,
2014, for each non-employee director was as follows: Robertson – 3,894 shares; Rodgers – 3,894; and Calerich – 3,938. In addition, each of the three independent directors was granted 1,679 shares of restricted stock on April 1, 2014, subject to vesting and forfeiture. All restricted shares are considered issued and outstanding shares of the Company’s common stock at the grant date and have the same dividend and voting rights as other common stock.
A summary of the status of the Company’s non-vested shares under the Director Compensation Plan as of March 31, 2014 and 2013, and changes during the years ended on those dates is presented below:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant
|
|
|
|
|
|
Grant
|
|
|
|
|
|
|
Date Fair
|
|
|
|
|
|
Date Fair
|
|
|
|
Shares
|
|
|
Value
|
|
|
Shares
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares, beginning of year
|
|
|
11,755
|
|
|
$
|
207,000
|
|
|
|
14,779
|
|
|
$
|
186,000
|
|
Granted
|
|
|
6,525
|
|
|
|
108,000
|
|
|
|
4,929
|
|
|
|
108,000
|
|
Vested
|
|
|
(6,554
|
)
|
|
|
(99,000
|
)
|
|
|
(7,953
|
)
|
|
|
(87,000
|
)
|
Forfeited
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Value
|
|
|
Shares
|
|
|
Value
|
|
Non-vested shares, end of year |
|
|
11,726 |
|
|
$ |
216,000 |
|
|
|
11,755 |
|
|
$ |
207,000 |
|
As of March 31, 2014, there was $216,000 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Director Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.70 years.
Share-based compensation expense of $110,000 and $100,000 was recognized during the years ended March 31, 2014 and 2013, respectively, for restricted share grants to independent directors.
The 2011 Equity Incentive Compensation Plan (“the Equity Plan”) was adopted by the Board on July 14, 2011, subject to the approval of our Stockholders, which was obtained on September 23, 2011, making the plan effective as of September 23, 2011. The Equity Plan was established to promote our interests and the interests of our Stockholders by encouraging the participants, namely employees, to increase their equity interest in us, thereby giving them an added incentive to work toward the Company’s continued growth and success, all the while enabling us to compete for the services of the individuals needed for our continued growth and success. Awards are in the form of restricted shares of
common stock. These awards are subject to such restrictions as the Compensation Committee of the Board of Directors may impose, including vesting and risk of forfeiture.
The Equity Plan allows up to 150,000 shares of the Company’s common stock to be issued to personnel under the plan. During the year ended March 31, 2014, 5,013 shares were granted. Subsequent to the grants, 2,713 shares were forfeited. Subsequent to March 31, 2014, 3,831 shares have been granted. Accordingly, as of June 10, 2014, 135,202 shares of common stock remain available for issuance under the Equity Plan.
A summary of the status of the Company’s non-vested shares under the Equity Incentive Compensation Plan as of March 31, 2014 and 2013, and changes during the years ended on those dates is presented below:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Grant
|
|
|
|
|
|
Grant
|
|
|
|
|
|
|
Date Fair
|
|
|
|
|
|
Date Fair
|
|
|
|
Shares
|
|
|
Value
|
|
|
Shares
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares, beginning of year
|
|
|
7,466
|
|
|
$
|
128,000
|
|
|
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
5,013
|
|
|
|
83,000
|
|
|
|
9,027
|
|
|
|
155,000
|
|
Vested
|
|
|
(2,918
|
)
|
|
|
(47,000
|
)
|
|
|
(1,275
|
)
|
|
|
(21,000
|
)
|
Forfeited
|
|
|
(2,713
|
)
|
|
|
(30,000
|
)
|
|
|
(286
|
)
|
|
|
(6,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares, end of year
|
|
|
6,848
|
|
|
$
|
134,000
|
|
|
|
7,466
|
|
|
$
|
128,000
|
|
Share-based compensation expense of $48,000 and $70,000 was recognized during the years ended March 31, 2014 and 2013, respectively, for restricted share grants to employees.
As of March 31, 2014, there was $134,000 of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Equity Incentive Compensation Plan. That cost is expected to be recognized over a weighted-average period of 1.78 years.
Treasury Shares. On October 22, 2008, the Company’s Board authorized a share buyback program for the Company to repurchase up to 5,000 shares of its common stock for a period of up to 18 months. The program did not require the Company to repurchase any specific number of shares, and the Company may terminate the repurchase program at any time. On November 13, 2009, the Board increased the number of shares authorized for repurchase to 15,000 shares. On February
10, 2010, the Board extended the termination date of the program from April 22, 2010 to October 22, 2011. On November 7, 2011, the Board further extended the termination date of the program from October 22, 2011 to October 22, 2013. On November 11, 2013, the Board approved a motion that allowed for up to $5,000 per year to be used to buy back blocks of 99 shares or less. During the year ended March 31, 2014, 30 shares were repurchased at an average price of $17 under the share buyback program and 10,298 shares remain available for future repurchase. No treasury shares have been retired.
9. Income Tax
The provision for income tax for the years ending March 31, 2014 and 2013 is comprised of the following:
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
Federal
|
|
$
|
(387,000
|
)
|
|
$
|
40,000
|
|
State
|
|
|
(3,000
|
)
|
|
|
22,000
|
|
Total current income tax (benefit) expense
|
|
|
(390,000
|
)
|
|
|
62,000
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
Federal
|
|
|
1,439,000
|
|
|
|
226,000
|
|
State
|
|
|
76,000
|
|
|
|
14,000
|
|
Total deferred income tax expense
|
|
|
1,515,000
|
|
|
|
240,000
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
1,125,000
|
|
|
$
|
302,000
|
|
A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the years ended March 31, 2014 and 2013 is as follows:
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Federal tax at statutory rate
|
|
$
|
1,722,000
|
|
|
$
|
708,000
|
|
State taxes, net of federal benefit
|
|
|
55,000
|
|
|
|
18,000
|
|
Excess percentage depletion
|
|
|
(678,000
|
)
|
|
|
(415,000
|
)
|
Changes in state rates and other adjustments to deferred taxes
|
|
|
26,000
|
|
|
|
(9,000
|
)
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
1,125,000
|
|
|
$
|
302,000
|
|
|
|
|
|
|
|
|
|
|
Effective rate expressed as a percentage of income before income tax
|
|
|
22.2
|
%
|
|
|
14.5
|
%
|
The overall effective tax rate expressed as a percentage of book income before income tax for the year ended March 31, 2014 was 22.2%, as compared to the year ended March 31, 2013 when it was 14.5%, was higher due to a decrease in the percentage of current year excess depletion deduction between the comparable periods.
Income tax payments, net, were $1,000 and $341,000 for the years ended March 31, 2014 and 2013, respectively.
Net deferred tax assets and liabilities were comprised of:
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
Statutory depletion carry-forward
|
|
$
|
2,190,000
|
|
|
$
|
1,467,000
|
|
Other accruals
|
|
|
103,000
|
|
|
|
131,000
|
|
Allowance for doubtful accounts
|
|
|
5,000
|
|
|
|
14,000
|
|
|
|
|
|
|
|
|
|
|
Gross deferred tax assets
|
|
|
2,298,000
|
|
|
|
1,612,000
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and intangible drilling costs
|
|
|
(6,784,000
|
)
|
|
|
(4,583,000
|
)
|
|
|
|
|
|
|
|
|
|
Gross deferred tax liabilities
|
|
|
(6,784,000
|
)
|
|
|
(4,583,000
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liabilities
|
|
$
|
(4,486,000
|
)
|
|
$
|
(2,971,000
|
)
|
Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.
The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are the years ended March 31, 2010 through 2014.
ASC 740 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements. Tax positions must meet a “more-likely-than-not” recognition threshold before a benefit is recognized in the financial statements. As of March 31, 2014, the Company has not recorded a liability for uncertain tax positions. The Company recognizes interest and penalties related to uncertain tax positions in income tax (benefit)/expense. No interest and penalties related to uncertain tax positions were incurred during the years ended March 31, 2014 and 2013.
As of March 31, 2014, the Company has approximately $270,000 of state net operating loss carryovers. Under the various existing state laws, these net operating loss carryovers may be utilized to offset state taxable income through the year ended March 31, 2033. A portion of the net operating loss carryover begins to expire in 2018.
10. Related Party Transactions
The Company maintains a policy permitting officers or directors to assign to the Company or receive assignments from the Company in oil and gas prospects, but only on the same terms and conditions as accepted by independent third parties. This policy also allows officers or directors and the Company to participate together in oil and gas prospects generated by independent third parties, but only on the same terms and conditions as accepted by non-related third parties. During the years ended March 31, 2014 and 2013,
no director or officer participated with the Company in any new oil and gas transaction. In prior years, Mr. Singleton has participated with the Company in the acquisition of producing properties on the same terms and conditions as other third parties. As such, Mr. Singleton paid for his proportionate share of the acquisition costs at the time of the acquisition. With respect to his working interest in the three producing wells in which he currently has an ownership, as of March 31, 2014 and 2013, the Company had no accrued balance due to or due from Mr. Singleton.
11. Oil and Gas Properties
The aggregate amount of capitalized costs related to oil and gas property and the aggregate amount of related accumulated depletion and impairment as of March 31, 2014 and 2013 are as follows:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
67,186,000
|
|
|
$
|
53,265,000
|
|
Unproved properties
|
|
|
773,000
|
|
|
|
2,156,000
|
|
Less accumulated depletion and impairment
|
|
|
(31,496,000
|
)
|
|
|
(27,729,000
|
)
|
|
|
|
|
|
|
|
|
|
Total oil and gas properties, net
|
|
$
|
36,463,000
|
|
|
$
|
27,692,000
|
|
The Company divested its interests in a salt water disposal well located in North Dakota for proceeds of $292,000 in the year ended March 31, 2014, which was accounted for as a reduction to proved properties. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas property unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves.
The following shows, by category and year incurred, the oil and gas property costs applicable to unproved property that were excluded from the full cost pool depletion computation as of March 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Exploration
|
|
|
Development
|
|
|
Acquisition
|
|
|
Unproved
|
|
Costs Incurred During Year Ended
|
|
Costs
|
|
|
Costs
|
|
|
Costs
|
|
|
Property
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
224,000
|
|
|
$
|
244,000
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
443,000
|
|
|
|
443,000
|
|
Prior Years
|
|
|
-
|
|
|
|
-
|
|
|
|
106,000
|
|
|
|
106,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
773,000
|
|
|
$
|
773,000
|
|
Costs incurred in oil and gas property development, exploration and acquisition activities during the years ended March 31, 2014 and 2013 are summarized as follows:
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Development costs
|
|
$
|
12,342,000
|
|
|
$
|
13,077,000
|
|
Exploration costs
|
|
|
488,000
|
|
|
|
-
|
|
Acquisitions:
|
|
|
|
|
|
|
|
|
Proved
|
|
|
-
|
|
|
|
-
|
|
Unproved
|
|
|
-
|
|
|
|
823,000
|
|
|
|
|
|
|
|
|
|
|
Total costs of development, exploration and acquisition activities
|
|
$
|
12,830,000
|
|
|
$
|
13,900,000
|
|
12. Subsequent Events
On May 15, 2014, the Company announced that it had entered into an Exchange Agreement with Oak Valley Resources, LLC (“Oak Valley”) whereby the membership interests in three subsidiaries of Oak Valley, inclusive of producing assets, undeveloped acreage and an estimated $138 million of cash, would be contributed and transferred to the Company in exchange for the issuance of approximately 9.1 million shares of the Company’s common stock (“Common Stock”) to Oak Valley (the “Exchange”). Upon completion of the Exchange, current
Company stockholders will own 16% of the Company’s outstanding Common Stock and Oak Valley will own 84% of the Company’s outstanding Common Stock. Closing conditions include the approval by our shareholders for the issuance to Oak Valley of the Common Stock in the Exchange, approval by our shareholders of an amendment to the certificate of incorporation to increase our authorized capital to 100,000,000 shares of Common Stock and 20,000,000 of Preferred Stock and listing approval by the NYSE MKT of the Common Stock to be issued to Oak Valley in the Exchange. It is anticipated that the Exchange transaction will not be completed until the third calendar quarter of 2014, subject to customary and specific closing
conditions.
The foregoing summary of the Exchange does not purport to be complete and is qualified in its entirety by statements, documents and other information contained in the Current Report on Form 8-K as filed by the Company with the U.S. Securities Exchange Commission on May 16, 2014.
13. Unaudited Oil and Gas Reserves Information
As of March 31, 2014 and 2013, 100% of the estimated oil and gas reserves presented herein were derived from reports prepared by independent petroleum engineering firm Ryder Scott Company.
Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered through wells yet to be completed.
Analysis of Changes in Proved Reserves. Estimated quantities of proved developed reserves (all of which are located within the United States), as well as the changes in proved developed and proved undeveloped reserves during the periods indicated, are presented in the following tables:
Proved Reserves
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
2,457,000
|
|
|
|
2,786,000
|
|
|
|
1,227,000
|
|
|
|
646,000
|
|
Revisions of previous estimates1
|
|
|
(88,000
|
)
|
|
|
245,000
|
|
|
|
101,000
|
|
|
|
148,000
|
|
Extensions and discoveries2
|
|
|
359,000
|
|
|
|
572,000
|
|
|
|
1,245,000
|
|
|
|
1,936,000
|
|
Sales of reserves in place
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
7,000
|
|
|
|
163,000
|
|
Purchase of reserves
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production3
|
|
|
(174,000
|
)
|
|
|
(190,000
|
)
|
|
|
(123,000
|
)
|
|
|
(107,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
2,554,000
|
|
|
|
3,413,000
|
|
|
|
2,457,000
|
|
|
|
2,786,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year
|
|
|
1,388,000
|
|
|
|
1,182,000
|
|
|
|
1,077,000
|
|
|
|
515,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
1,526,000
|
|
|
|
1,773,000
|
|
|
|
1,388,000
|
|
|
|
1,182,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of year4
|
|
|
1,069,000
|
|
|
|
1,604,000
|
|
|
|
150,000
|
|
|
|
131,000
|
|
PUD converted to PDP
|
|
|
(405,000
|
)
|
|
|
(607,000
|
)
|
|
|
-
|
|
|
|
-
|
|
PUD added during the year
|
|
|
338,000
|
|
|
|
633,000
|
|
|
|
919,000
|
|
|
|
1,473,000
|
|
Revisions of previous estimates
|
|
|
26,000
|
|
|
|
10,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
|
1,028,000
|
|
|
|
1,640,000
|
|
|
|
1,069,000
|
|
|
|
1,604,000
|
|
1 Revisions of Previous Estimates – Estimates reflect an overall steady trend of increases in oil and gas prices since December 2008, when prices reached a 5-year low, offset by normal decline curves in wells.
2 Extensions and Discoveries – Additions during the year ended March 31, 2014 consisted of 62 wells, 57 in North Dakota and five in Montana. Extensions and discoveries during the year ended March 31, 2013 consisted of 103 wells, 102 in North Dakota and one in Louisiana.
3 Production – Volumes of oil and gas that were produced were removed from reserves during the year.
4 Proved undeveloped reserves - Positive revisions of 14,000 BOE, or 1%, were made to the March 31, 2013 estimated proved undeveloped reserves balance. The primary cause for these revisions was due to increases in pricing which extended the economic life of the wells. Within portions of the Company’s areas of operation, actual well results underperformed relative to the proved undeveloped forecasts in the March 31, 2013 reserve report. The proved undeveloped forecasts in these areas have been adjusted to reflect these well performances in the March 31, 2014 reserve report.
The table below sets forth a standardized measure of the estimated discounted future net cash flows attributable to the Company’s proved oil and gas reserves. Estimated future cash inflows were computed by applying the 12-month average price of oil and gas on the first day of each month to the estimated future production of proved oil and gas reserves as of March 31, 2014 and 2013. The future production and development costs represent the estimated future expenditures to be incurred in producing and developing the proved reserves, assuming continuation of existing economic conditions. Discounting the annual net cash flows at 10% illustrates the impact of timing on these future cash flows.
Standardized Measure of Estimated Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
246,908,000
|
|
|
$
|
217,487,000
|
|
Future cash outflows:
|
|
|
|
|
|
|
|
|
Production cost
|
|
|
(91,392,000
|
)
|
|
|
(88,280,000
|
)
|
Development cost
|
|
|
(25,563,000
|
)
|
|
|
(28,255,000
|
)
|
Future income tax
|
|
|
(28,829,000
|
)
|
|
|
(25,675,000
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
101,124,000
|
|
|
|
75,277,000
|
|
Adjustment to discount future annual net cash flows at 10%
|
|
|
(52,069,000
|
)
|
|
|
(43,661,000
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
49,055,000
|
|
|
$
|
31,616,000
|
|
The following table summarizes the principal factors comprising the changes in the standardized measure of estimated discounted net cash flows for each of the years ended March 31, 2014 and 2013:
Changes in Standardized Measure of Estimated Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
|
|
Standardized measure, beginning of year
|
|
$
|
31,616,000
|
|
|
$
|
23,183,000
|
|
Sales of oil and gas, net of production cost1
|
|
|
(11,901,000
|
)
|
|
|
(6,558,000
|
)
|
Net change in sales prices, net of production cost
|
|
|
10,126,000
|
|
|
|
(9,648,000
|
)
|
Discoveries, extensions and improved recoveries, net of future development cost
|
|
|
6,021,000
|
|
|
|
21,075,000
|
|
Change in future development costs
|
|
|
-
|
|
|
|
-
|
|
Development costs incurred during the period that reduced future development cost
|
|
|
9,955,000
|
|
|
|
(2,757,000
|
)
|
Sales of reserves in place
|
|
|
-
|
|
|
|
-
|
|
Revisions of quantity estimates
|
|
|
(1,487,000
|
)
|
|
|
2,036,000
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
Accretion of discount
|
|
|
5,729,000
|
|
|
|
3,780,000
|
|
Net change in income tax
|
|
|
(941,000
|
)
|
|
|
3,320,000
|
|
Purchase of reserves
|
|
|
-
|
|
|
|
-
|
|
Changes in timing of rates of production
|
|
|
(63,000
|
)
|
|
|
(2,815,000
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of year
|
|
$
|
49,055,000
|
|
|
$
|
31,616,000
|
|
|
1
|
During the fiscal year ended March 31, 2014, we have revised our disclosure to include $971,000 of production taxes previously excluded from Sales of oil and gas, net of production costs as of March 31, 2014.
|
Unaudited Financial Statements of Earthstone Energy, Inc. as of and for the Three Months Ended June 30, 2014 and 2013
Earthstone Energy, Inc.
|
|
Condensed Consolidated Balance Sheets
|
|
Page 1 of 2
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,119,000
|
|
|
$
|
2,671,000
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
4,282,000
|
|
|
|
3,895,000
|
|
Joint interest and other receivables
|
|
|
271,000
|
|
|
|
758,000
|
|
|
|
|
|
|
|
|
|
|
Other current assets
|
|
|
887,000
|
|
|
|
1,043,000
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
7,559,000
|
|
|
|
8,367,000
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, full cost method:
|
|
|
|
|
|
|
|
|
Proved properties
|
|
|
69,850,000
|
|
|
|
67,186,000
|
|
Unproved properties
|
|
|
687,000
|
|
|
|
773,000
|
|
Accumulated depletion and impairment
|
|
|
(32,613,000
|
)
|
|
|
(31,496,000
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
|
37,924,000
|
|
|
|
36,463,000
|
|
|
|
|
|
|
|
|
|
|
Support equipment and other non-current assets
|
|
|
|
|
|
|
|
|
net of accumulated depreciation of ($542,000) and ($514,000), respectively
|
|
|
785,000
|
|
|
|
791,000
|
|
|
|
|
|
|
|
|
|
|
Total non-current assets
|
|
|
38,709,000
|
|
|
|
37,254,000
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
46,268,000
|
|
|
$
|
45,621,000
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
Earthstone Energy, Inc.
|
|
Condensed Consolidated Balance Sheets
|
|
Page 2 of 2
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
(Unaudited)
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
341,000
|
|
|
$
|
430,000
|
|
Accrued liabilities
|
|
|
5,670,000
|
|
|
|
5,243,000
|
|
Total current liabilities
|
|
|
6,011,000
|
|
|
|
5,673,000
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
8,000,000
|
|
|
|
9,000,000
|
|
Deferred tax liability
|
|
|
4,695,000
|
|
|
|
4,486,000
|
|
Asset retirement obligation, less current portion
|
|
|
2,126,000
|
|
|
|
2,068,000
|
|
Total long-term liabilities
|
|
|
14,821,000
|
|
|
|
15,554,000
|
|
Total liabilities
|
|
|
20,832,000
|
|
|
|
21,227,000
|
|
|
|
|
|
|
|
|
|
|
Shareholders’ equity:
|
|
|
|
|
|
|
|
|
Preferred shares, $0.001 par value, 600,000 authorized
|
|
|
-
|
|
|
|
-
|
|
and none issued or outstanding
|
|
|
|
|
|
|
|
|
Common shares, $0.001 par value, 6,400,000 shares authorized and
|
|
|
18,000
|
|
|
|
18,000
|
|
1,762,000 and 1,753,000 shares issued, respectively
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
23,481,000
|
|
|
|
23,436,000
|
|
Treasury stock, at cost, 15,000 and 24,000 shares, respectively
|
|
|
(458,000)
|
|
|
|
(458,000)
|
|
Retained earnings
|
|
|
2,395,000
|
|
|
|
1,398,000
|
|
|
|
|
|
|
|
|
|
|
Total shareholders’ equity
|
|
|
25,436,000
|
|
|
|
24,394,000
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders’ equity
|
|
$
|
46,268,000
|
|
|
$
|
45,621,000
|
|
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
Earthstone Energy, Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
Revenues:
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
5,214,000
|
|
|
$
|
3,582,000
|
|
Well service and water-disposal revenue
|
|
|
24,000
|
|
|
|
13,000
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
5,238,000
|
|
|
|
3,595,000
|
|
|
|
|
|
|
|
|
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Oil and gas production
|
|
|
1,019,000
|
|
|
|
835,000
|
|
Production tax
|
|
|
473,000
|
|
|
|
309,000
|
|
Well service and water-disposal
|
|
|
19,000
|
|
|
|
37,000
|
|
Depletion and depreciation
|
|
|
1,145,000
|
|
|
|
786,000
|
|
Accretion of asset retirement obligation
|
|
|
53,000
|
|
|
|
49,000
|
|
General and administrative
|
|
|
1,258,000
|
|
|
|
693,000
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
3,967,000
|
|
|
|
2,709,000
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
1,271,000
|
|
|
|
886,000
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest and other income
|
|
|
4,000
|
|
|
|
8,000
|
|
Interest and other expenses
|
|
|
(61,000)
|
|
|
|
(33,000)
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(57,000)
|
|
|
|
(25,000)
|
|
|
|
|
|
|
|
|
|
|
Income before income tax
|
|
|
1,214,000
|
|
|
|
861,000
|
|
|
|
|
|
|
|
|
|
|
Current income tax expense
|
|
|
6,000
|
|
|
|
27,000
|
|
Deferred income tax expense
|
|
|
211,000
|
|
|
|
141,000
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense
|
|
|
217,000
|
|
|
|
168,000
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
997,000
|
|
|
$
|
693,000
|
|
|
|
|
|
|
|
|
|
|
Per share amounts:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.58
|
|
|
$
|
0.40
|
|
Diluted
|
|
$
|
0.58
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1,719,042
|
|
|
|
1,710,829
|
|
Diluted
|
|
|
1,724,512
|
|
|
|
1,710,829
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
Earthstone Energy, Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
Net income
|
|
$
|
997,000
|
|
|
$
|
693,000
|
|
Adjustments to reconcile net income to net cash provided by
|
|
|
|
|
|
|
|
|
operating activities:
|
|
|
|
|
|
|
|
|
Depletion and depreciation
|
|
|
1,145,000
|
|
|
|
786,000
|
|
Deferred income tax expense
|
|
|
211,000
|
|
|
|
141,000
|
|
Accretion of asset retirement obligation
|
|
|
53,000
|
|
|
|
49,000
|
|
Share-based compensation
|
|
|
45,000
|
|
|
|
47,000
|
|
Amortization of deferred financing costs
|
|
|
4,000
|
|
|
|
3,000
|
|
Change in:
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
100,000
|
|
|
|
419,000
|
|
Other current assets
|
|
|
(36,000)
|
|
|
|
34,000
|
|
Accounts payable, accrued and other liabilities
|
|
|
125,000
|
|
|
|
716,000
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
2,644,000
|
|
|
|
2,888,000
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Oil and gas properties
|
|
|
(2,170,000)
|
|
|
|
(3,718,000)
|
|
Purchases of support equipment and other non-current assets
|
|
|
(26,000)
|
|
|
|
(144,000)
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(2,196,000)
|
|
|
|
(3,862,000)
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Repayments on long-term debt
|
|
|
(1,000,000)
|
|
|
|
-
|
|
Borrowings on long-term debt
|
|
|
-
|
|
|
|
1,000,000
|
|
Deferred financing fees
|
|
|
-
|
|
|
|
(4,000)
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities
|
|
|
(1,000,000)
|
|
|
|
996,000
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents:
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(552,000)
|
|
|
|
22,000
|
|
Cash and cash equivalents, beginning of period
|
|
|
2,671,000
|
|
|
|
2,180,000
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
2,119,000
|
|
|
$
|
2,202,000
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
62,000
|
|
|
$
|
31,000
|
|
Cash paid for income tax
|
|
$
|
-
|
|
|
$
|
-
|
|
Non-cash:
|
|
|
|
|
|
|
|
|
Increase in oil and gas property due to asset retirement obligation
|
|
$
|
8,000
|
|
|
$
|
19,000
|
|
Accrued capital expenditures
|
|
$
|
208,000
|
|
|
$
|
903,000
|
|
Prepaid capital expenditures
|
|
$
|
192,000
|
|
|
$
|
-
|
|
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements
Earthstone Energy, Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
1. Basis of Presentation
The accompanying interim financial statements of Earthstone Energy, Inc. (formerly Basic Earth Science Systems, Inc.) are unaudited. However, in the opinion of management, the interim data includes any applicable adjustments necessary for a fair presentation of the financial and operational results for the interim period according to generally accepted accounting principles in the United States of America (“U.S. GAAP”).
At the directive of the Securities and Exchange Commission (“SEC”) to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Earthstone Energy, Inc. and its wholly-owned subsidiary. When such terms are used in this manner throughout the notes to the unaudited condensed consolidated financial statements, they are in reference only to the corporation, Earthstone Energy, Inc. and its subsidiaries, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees.
The financial statements included herein have been prepared by the Company pursuant to the rules and regulations of the SEC. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and suggest that these financial statements be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the previous fiscal year-end.
Further, the results of operations for the three months covered by this report, are not necessarily indicative of the operating results that may be expected for the full fiscal year.
Pending Strategic Combination. On May 15, 2014, the Company and Oak Valley Resources, LLC (“Oak Valley”), entered into an Exchange Agreement (the “Exchange Agreement”). The Exchange Agreement provides that upon the terms and subject to the conditions set forth in the Exchange Agreement, Oak Valley will contribute to the Company the membership interests of its three subsidiaries, each a limited liability company, inclusive of producing assets, undeveloped acreage and an estimated $138 million in cash (now an estimated $142.5 million) and contractually obligated capital contributions, in
exchange for the issuance of approximately 9.1 million shares of the Company’s common stock (“Common Stock”) to Oak Valley (the “Exchange”). Following the Exchange, current Earthstone stockholders will own 16% of the Company’s outstanding Common Stock and Oak Valley will own 84% of the Company’s outstanding Common Stock. The Exchange Agreement has been approved by the Board of Directors of Earthstone and the board of managers of Oak Valley.
Pending closing of the Exchange, the Company has agreed in the Exchange Agreement to various covenants and restrictions related to the conduct of its business including, among others (i) to conduct its business in the ordinary course consistent with past practices, (ii) to retain the services of its present officers and key employees, (iii) to use commercially reasonable efforts to comply, in all material respects, with applicable laws and material contracts, (iv) not to issue, sell, grant, dispose of, accelerate or modify, as appropriate, any of its securities, (v) not to redeem, purchase or acquire any of its outstanding securities, except in connection with vesting, settlement of, forfeiture of, or tax withholding with respect to, any equity or equity-based
awards granted under any Company equity plan that is outstanding as of the date of the Exchange Agreement, (vi) not to incur, refinance or assume any indebtedness for borrowed money other than borrowings under the Company’s existing credit facility, (viii) not to sell, transfer, lease, farmout or otherwise dispose of any of the Company’s properties with a fair market value in excess of $1 million, (ix) not to make any unbudgeted capital expenditure(s) in excess of $5 million without the consultation and consent of Oak Valley, which consent shall not be unreasonably withheld, delayed or conditioned, or except as may be reasonably required to conduct emergency operations, repairs or replacements on any well, pipeline or other facility, or (x) not to (A) materially increase the compensation of any executive
officer, (B) pay any bonus or incentive compensation, (C) grant any new equity or non-equity based compensation award, except as required by applicable law or any employee benefit plans. The Company does not anticipate that the subject covenants and restrictions agreed to in the Exchange Agreement will materially interfere with, change, alter or otherwise impact the Company’s ongoing continuing activities over the next several months until the Exchange is consummated or otherwise terminated.
The foregoing descriptions of the Exchange and the Exchange Agreement do not purport to be complete and are qualified in their entirety by the other terms and provisions of the Exchange Agreement, a copy of which is attached to the Current Report on Form 8-K as filed by the Company with the SEC on May 16, 2014. A copy of the subject Form 8-K can be obtained by accessing the SEC’s website at http://www.sec.gov.
Fair Value Measurements. Financial instruments and nonfinancial assets and liabilities, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, and long-term debt, all of which are considered to be representative of their fair market value, due to the short-term highly liquid nature and/or the floating interest rate structure of these instruments.
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions concern matters that are inherently uncertain. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from those estimates.
Recent Accounting Pronouncements. In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This ASU requires the Company to disclose both net and gross information about assets and liabilities that have been offset. The disclosures under this new guidance are required to be provided retrospectively for all comparative periods presented. The Company was required to implement this guidance effective for the first quarter of fiscal 2014. The adoption of ASU 2011-11 did not have a material impact on its consolidated financial statements.
In July 2013, the FASB issued, ASU No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”). ASU 2013-11 addresses the diversity in practice that exists for the balance sheet presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. ASU No. 2013-11 is effective for the Company’s fiscal quarter ending June 30, 2014. ASU 2013-11
impacts balance sheet presentation only. The impact of the new rule is not material.
2. Earnings Per Share
Basic earnings per share attributable to Earthstone shareholders is computed by dividing net income attributable to Earthstone shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share attributable to Earthstone shareholders is computed by dividing the net income attributable to Earthstone shareholders by the weighted average number of common shares outstanding during the period adjusted to include the effects of potentially dilutive securities. Potentially dilutive securities include incremental shares issuable upon the vesting of common shares issued to the employees and directors of Earthstone.
The amounts used in computing earnings per share and the effects of potentially dilutive securities on the weighted average number of common shares were as follows:
|
|
06/30/14
|
|
|
06/30/13
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
Net income attributable to Earthstone Energy, Inc.
|
|
|
|
|
|
|
shareholders
|
|
$
|
997,000
|
|
|
$
|
693,000
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares used in basic earnings
|
|
|
|
|
|
|
|
|
per share
|
|
|
1,719,042
|
|
|
|
1,710,829
|
|
|
|
|
06/30/14 |
|
|
|
06/30/13
|
|
|
|
|
(Unaudited) |
|
|
|
(Unaudited) |
|
Effects of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested common shares*
|
|
|
5,470
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares used in diluted
|
|
|
|
|
|
|
|
|
earnings per share
|
|
|
1,724,512
|
|
|
|
1,710,829
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share attributable to Earthstone
|
|
|
|
|
|
|
|
|
Energy, Inc. shareholders
|
|
$
|
0.58
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share attributable to Earthstone
|
|
|
|
|
|
|
|
|
Energy, Inc. shareholders
|
|
$
|
0.58
|
|
|
$
|
0.40
|
|
* As of June 30, 2013, we have excluded unvested common shares outstanding from the calculation of diluted earnings per share, as the inclusion of these shares would have been anti-dilutive.
3. Other Current Assets
|
|
06/30/14
|
|
|
03/31/14
|
|
|
|
(Unaudited)
|
|
|
|
|
Prepaid income tax
|
|
$
|
373,000
|
|
|
$
|
379,000
|
|
Lease and well equipment inventory
|
|
|
310,000
|
|
|
|
310,000
|
|
Other current assets
|
|
|
73,000
|
|
|
|
40,000
|
|
Drilling and completion cost prepayments
|
|
|
71,000
|
|
|
|
223,000
|
|
Prepaid insurance premiums
|
|
|
60,000
|
|
|
|
91,000
|
|
Total other current assets
|
|
$
|
887,000
|
|
|
$
|
1,043,000
|
|
4. Accrued Liabilities
|
|
06/30/14
|
|
|
03/31/14
|
|
|
|
(Unaudited)
|
|
|
|
|
Accrued operations payable
|
|
$
|
4,574,000
|
|
|
$
|
4,209,000
|
|
Accrued compensation
|
|
|
433,000
|
|
|
|
411,000
|
|
Short-term asset retirement obligation
|
|
|
320,000
|
|
|
|
317,000
|
|
Accrued income tax payable and other
|
|
|
176,000
|
|
|
|
180,000
|
|
Revenue and production taxes payable
|
|
|
167,000
|
|
|
|
126,000
|
|
Total accrued liabilities
|
|
$
|
5,670,000
|
|
|
$
|
5,243,000
|
|
5. Oil and Gas Properties
|
|
06/30/14
|
|
|
03/31/14
|
|
|
|
(Unaudited)
|
|
|
|
|
Proved properties
|
|
$
|
69,850,000
|
|
|
$
|
67,186,000
|
|
Unproved properties
|
|
|
687,000
|
|
|
|
773,000
|
|
Less accumulated depletion and impairment
|
|
|
(32,613,000)
|
|
|
|
(31,496,000)
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
37,924,000
|
|
|
$
|
36,463,000
|
|
As of June 30, 2014, the Company has recorded $69,850,000 as proved property costs. As of March 31, 2014, the Company had recorded $67,186,000 as proved property costs. Additions of $2,578,000 have been recorded during the three months ended June 30, 2014, and included in these additions are $2,561,000 related to intangible drilling and completion costs and tangible drilling and completion costs. Of the total additions recorded during the three months ended June 30, 2014, 80% relate to our work in North Dakota.
As of June 30, 2014, the Company has recorded $687,000 as unproved property costs. As of March 31, 2014, the Company had recorded $773,000 as unproved property costs. For the three months ended June 30, 2014, the Company recorded additional unproved property costs of $19,000 related to wells in progress. During the three months ended June 30, 2014, $49,000 in well costs and $55,000 in costs related to acreage were transferred from unevaluated to depletable properties. In addition, there
were leased acreage expirations of approximately $1,000.
6. Long-Term Debt
7. Income Tax
The provision for income tax is comprised of:
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
Current:
|
|
|
|
Federal
|
|
$
|
2,000
|
|
|
$
|
20,000
|
|
State
|
|
|
4,000
|
|
|
|
7,000
|
|
Total current income tax
|
|
|
6,000
|
|
|
|
27,000
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
Federal
|
|
|
200,000
|
|
|
|
133,000
|
|
State
|
|
|
11,000
|
|
|
|
8,000
|
|
Total deferred income tax
|
|
|
211,000
|
|
|
|
141,000
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
217,000
|
|
|
$
|
168,000
|
|
A reconciliation between the income tax provision at the statutory rate on income tax and the income tax provision for the three months ended is as follows:
|
|
Three Months Ended June 30, |
|
|
|
|
|
|
2013
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
Federal tax at statutory rate
|
|
$
|
413,000
|
|
|
$
|
292,000
|
|
State taxes, net of federal benefit
|
|
|
12,000
|
|
|
|
9,000
|
|
Excess percentage depletion
|
|
|
(203,000)
|
|
|
|
(135,000)
|
|
Other adjustments, net
|
|
|
(5,000)
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
217,000
|
|
|
$
|
168,000
|
|
Effective rate expressed as a percentage
of income before income tax
|
|
|
17.9%
|
|
|
|
19.5%
|
|
|
|
|
|
|
|
|
|
|
The overall effective tax rate expressed as a percentage of book income before income tax for the current three month period, as compared to the same period in the prior year, was lower due to an increase in the deduction for excess percentage depletion related to an increase in annualized oil and gas sales.
Net deferred tax assets and liabilities were comprised of:
|
|
June 30,
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
(Unaudited)
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
Statutory depletion carry-forward
|
|
$
|
2,406,000
|
|
|
$
|
2,190,000
|
|
Net operating loss carry-forward
|
|
|
14,000
|
|
|
|
-
|
|
Other accruals
|
|
|
67,000
|
|
|
|
103,000
|
|
Allowance for doubtful accounts
|
|
|
5,000
|
|
|
|
5,000
|
|
|
|
|
|
|
|
|
|
|
Gross deferred tax assets
|
|
|
2,492,000
|
|
|
|
2,298,000
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Depletion, depreciation and intangible drilling costs
|
|
|
(7,187,000)
|
|
|
|
(6,784,000)
|
|
|
|
|
|
|
|
|
|
|
Gross deferred tax liabilities
|
|
|
(7,187,000)
|
|
|
|
(6,784,000)
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities, net
|
|
$
|
(4,695,000)
|
|
|
$
|
(4,486,000)
|
|
Projections of future income taxes and their timing require significant estimates with respect to future operating results. Accordingly, deferred taxes may change significantly as more information and data is gathered with respect to such events as changes in commodity prices, their effect on the estimate of oil and gas reserves and the depletion of these long-lived reserves.
The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions.
The Company’s federal income tax returns for the prior three tax years of filings and state income tax returns for the prior four years of tax filings are still subject to examination by tax authorities.
SUBJECT TO COMPLETION
EARTHSTONE ENERGY, INC.
PROXY FOR SPECIAL MEETING OF STOCKHOLDERS
The undersigned stockholder of Earthstone Energy, Inc. (“Earthstone”), acknowledges receipt of the Proxy Statement and Notice of Special Meeting of Stockholders to be held on ________, 2014, at _____ a.m., Denver Time, at Davis Graham & Stubbs LLP, 1550 Seventeenth Street, Suite 500, Denver, Colorado 80202, and hereby appoints __________ and __________, each with the power of substitution, as proxies to vote all the shares of the undersigned at said meeting and at all adjournments thereof, hereby ratifying and confirming all that said proxies may do or cause to be done by virtue hereof. The above-named proxies are instructed to vote all of the undersigned’s shares
as follows:
1.
|
Approval of the issuance of up to 9,124,452 shares of Earthstone common stock pursuant to the Exchange Agreement dated as of May 15, 2014, between Earthstone and Oak Valley Resources, LLC, a Delaware limited liability company (“Oak Valley”). Under the exchange agreement, Earthstone will acquire Oak Valley’s membership interests in its three wholly owned Texas limited liability companies, Oak Valley Operating, LLC, EF Non-Op, LLC, and Sabine River Energy, LLC (collectively, the “Oak Valley Subsidiaries”), in exchange for up to 9,124,452 shares of Earthstone common stock. At the conclusion of the transactions contemplated by the exchange agreement, the Oak Valley Subsidiaries will be wholly
owned subsidiaries of Earthstone;
|
o FOR o AGAINST oABSTAIN
2.
|
Approval of an amendment to Earthstone’s certificate of incorporation increasing the total shares of stock from 7,000,000 shares consisting of 6,400,000 shares of common stock, $0.001 par value per share, and 600,000 shares of preferred stock, $0.001 par value per share, to 120,000,000 shares of stock, consisting of 100,000,000 shares of common stock, $0.001 par value per share, and 20,000,000 shares of preferred stock, $0.001 par value per share;
|
o FOR o AGAINST oABSTAIN
3.
|
Approval and adoption of the Earthstone 2014 Long-Term Incentive Plan, which will, among other things, provide for the issuance of up to 750,000 shares of common stock under the plan to officers, directors and employees of the combined company following the exchange;
|
o FOR o AGAINST oABSTAIN
4.
|
Approval, by a non-binding advisory vote, of the Employee Severance Compensation Plan, which provides that under certain circumstances one of Earthstone’s named executive officers may be entitled to receive compensation in connection with the exchange; and
|
o FOR o AGAINST oABSTAIN
5.
|
Transaction of such other matters as may properly come before the special meeting or any adjournments or postponements of the special meeting.
|
o FOR o AGAINST oABSTAIN
YOU MAY VOTE IN FAVOR OF ALL THE ABOVE PROPOSALS WITHOUT CHECKING ANY OF THE ABOVE BOXES BY MERELY SIGNING, DATING AND RETURNING THIS PROXY. IF THIS PROXY IS PROPERLY EXECUTED AND ANY OF THE ABOVE BOXES ARE CHECKED, THIS PROXY WILL BE VOTED IN THE MANNER DIRECTED BY THE STOCKHOLDER.
PLEASE SIGN, DATE AND RETURN THIS PROXY IMMEDIATELY.
Date:
|
________, 2014
|
No. of Shares:
|
|
Sign Here:
|
|
|
|
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Signature(s) of Stockholders(s)
|
Please sign your name exactly as it appears on your stock certificate. If shares are held jointly, each holder should sign. Executors, trustees, and fiduciaries should so indicate when signing.
Telephone and Internet Voting Instructions
You can vote by telephone OR Internet! Available 24 hours a day 7 days a week!
Instead of mailing your proxy, you may choose one of the two voting methods outlined below to vote your proxy.
To vote using the telephone:
●
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Call toll free __________ any time on a touch-tone telephone. There is NO CHARGE to you for the call.
|
●
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Please have your proxy card and the last four digits of your Social Security Number or Tax Identification Number available. Follow the simple instructions provided by the recorded message.
|
To vote using the Internet:
●
|
Go to the following website: __________
|
●
|
Please have your proxy card and the last four digits of your Social Security Number or Tax Identification Number available. Enter the information requested on your computer screen and follow the simple instructions.
|
If you vote by telephone or the Internet, please DO NOT mail back this proxy card.
Proxies submitted by telephone or the Internet must be received by 11:59 p.m., Denver Time, on __________, 2014.
THANK YOU FOR VOTING.