SEC Info - Rex Energy Corp - ‘10-Q’ for 6/30/18

Rex Energy Corp – ‘10-Q’ for 6/30/18

Rex Energy Corp – ‘10-Q’ for 6/30/18

On: Wednesday, 8/8/18, at 4:36pm ET · For: 6/30/18 · Accession #: 1564590-18-20532 · File #: 1-33610

Previous ‘10-Q’: ‘10-Q’ on 5/15/18 for 3/31/18 · Latest ‘10-Q’: This Filing

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
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‘10-Q’ — Quarterly Report
Document Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

On: Wednesday, 8/8/18, at 4:36pm ET · For: 6/30/18 · Accession #: 1564590-18-20532 · File #: 1-33610

Previous ‘10-Q’: ‘10-Q’ on 5/15/18 for 3/31/18 · Latest ‘10-Q’: This Filing

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34Filing Table of Contents

‘10-Q’ — Quarterly ReportDocument Table of Contents

This is an HTML Document rendered as filed. [ Alternative Formats ]

Dates Referenced Herein and Documents Incorporated by Reference

Quarterly Report — Form 10-Q — Sect. 13 / 15(d) – SEA’34
Filing Table of Contents

‘10-Q’ — Quarterly Report
Document Table of Contents

Page	(sequential)		(alphabetic)	↑Top
		Alternative Formats (Word, et al.) Cautionary Statement Regarding Forward-Looking Statements Consolidated Balance Sheets as of June 30. 2018 (Unaudited) and December 31, 2017 Consolidated Statement of Changes in Stockholders' Equity (Unaudited) for the six-month period ended June 30, 2018 Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2018 and June 30, 2017 Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2018 and June 30, 2017 Controls and Procedures Exhibits Financial Statements Item 1 Item 1A Item 2 Item 3 Item 4 Item 6 Legal Proceedings Management's Discussion and Analysis of Financial Condition and Results of Operations Notes to Consolidated Financial Statements (Unaudited) Part Ii. Other Information Quantitative and Qualitative Disclosure About Market Risk Risk Factors Signatures
1	1st Page – Filing Submission
"	Cautionary Statement Regarding Forward-Looking Statements
"	Item 1
"	Financial Statements
"	Consolidated Balance Sheets as of June 30. 2018 (Unaudited) and December 31, 2017
"	Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2018 and June 30, 2017
"	Consolidated Statement of Changes in Stockholders' Equity (Unaudited) for the six-month period ended June 30, 2018
"	Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2018 and June 30, 2017
"	Notes to Consolidated Financial Statements (Unaudited)
"	Item 2
"	Management's Discussion and Analysis of Financial Condition and Results of Operations
"	Item 3
"	Quantitative and Qualitative Disclosure About Market Risk
"	Item 4
"	Controls and Procedures
"	Part Ii. Other Information
"	Legal Proceedings
"	Item 1A
"	Risk Factors
"	Item 6
"	Exhibits
"	Signatures

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Some of the information, including all of the estimates and assumptions, in this report contains forward-looking statements within the meaning of sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans and objectives of management for future operations, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “estimate,” “anticipate,” “believe” or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

	June 30, 2018 (unaudited)			December 31, 2017
ASSETS
Current Assets
Cash and Cash Equivalents	$	28,780		$	15,247
Restricted Cash		33,106			—
Accounts Receivable		28,588			25,974
Taxes Receivable		48			2,049
Short-Term Derivative Instruments		4,796			8,008
Inventory, Prepaid Expenses and Other		3,389			4,614
Total Current Assets		98,707			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,062,986			1,086,625
Unevaluated Oil and Gas Properties		174,608			186,523
Other Property and Equipment		20,066			19,640
Wells and Facilities in Progress		2,552			38,660
Pipelines		16,528			16,803
Total Property and Equipment		1,276,740			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(384,556	)		(463,899	)
Net Property and Equipment		892,184			884,352
Other Assets		35			44
Long-Term Derivative Instruments		1,463			1,719
Deferred Tax Assets - Long Term		130			130
Total Assets	$	992,519		$	942,137
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	82,679		$	62,354
Current Maturities of Long-Term Debt		261,315			834,325
Debtor-in Possession Term Loan Payable		35,000			—
Accrued Liabilities		30,936			45,218
Short-Term Derivative Instruments		19,095			14,892
Total Current Liabilities		429,025			956,789
Long-Term Derivative Instruments		12,075			14,249
Other Long-Term Debt		—			8,156
Other Deposits and Liabilities		—			7,153
Future Abandonment Cost		8,626			9,352
Liabilities Subject to Compromise		667,624			—
Total Liabilities	$	1,117,350		$	995,699
Commitments and Contingencies (See Note 13)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on June 30, 2018 and December 31, 2017	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,707,788 shares issued and outstanding on June 30, 2018 and 10,244,394 shares issued and outstanding on December 31, 2017.		11			10
Additional Paid-In Capital		654,721			652,917
Accumulated Deficit		(779,564	)		(706,490	)
Total Stockholders’ Equity		(124,831	)		(53,562	)
Total Liabilities and Stockholders’ Equity	$	992,519		$	942,137

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	75,155		$	47,457		$	140,180		$	99,522
Other Operating Revenue		3			5			7			11
TOTAL OPERATING REVENUE		75,158			47,462			140,187			99,533
OPERATING EXPENSES
Production and Lease Operating Expense		36,756			29,374			70,602			58,308
General and Administrative Expense		4,422			4,294			10,946			8,828
(Gain) Loss on Disposal of Assets		—			(124	)		647			(1,959	)
Impairment Expense		4,334			3,032			12,503			4,577
Exploration Expense		122			99			350			319
Depreciation, Depletion, Amortization and Accretion		16,953			15,501			32,081			30,969
Other Operating (Income) Expense		1,492			(98	)		1,695			(118	)
TOTAL OPERATING EXPENSES		64,079			52,078			128,824			100,924
INCOME (LOSS) FROM OPERATIONS		11,079			(4,616	)		11,363			(1,391	)
OTHER INCOME (EXPENSE)
Interest Expense		(14,118	)		(12,122	)		(36,765	)		(21,266	)
(Loss) Gain on Derivatives, Net		(14,328	)		10,386			(60,754	)		18,766
Other (Expense) Income		(13,952	)		20			(14,955	)		(7	)
Loss on Extinguishments of Debt		—			(3,271	)		—			(3,022	)
Reorganization Items, Net		28,635			—			28,635			—
TOTAL OTHER EXPENSE		(13,763	)		(4,987	)		(83,839	)		(5,529	)
LOSS BEFORE INCOME TAX		(2,684	)		(9,603	)		(72,476	)		(6,920	)
Income Tax Benefit		—			—			—			—
NET LOSS		(2,684	)		(9,603	)		(72,476	)		(6,920	)
Preferred Stock Dividends		(598	)		(598	)		(1,196	)		(1,196	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(3,282	)	$	(10,201	)	$	(73,672	)	$	(8,116	)
Earnings per common share:
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Basic - Weighted Average Shares of Common Stock Outstanding		10,708			9,881			10,587			9,825
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Diluted - Weighted Average Shares of Common Stock Outstanding		10,708			9,881			10,587			9,825

	For the Six Months Ended June 30,
	2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(72,476	)	$	(6,920	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		32,081			30,969
Loss (Gain) on Derivatives		60,754			(18,766	)
Cash Settlement of Derivatives		(6,862	)		(5,525	)
Equity-based Compensation Expense		1,200			571
Non-cash Exploration Expenses		—			13
Impairment Expense		12,503			4,577
Non-cash Interest Expense		2,881			12,431
Loss on Extinguishments of Debt		—			3,022
Loss (Gain) on Sale of Assets		647			(1,959	)
Non-cash Reorganization items, net		(43,509	)		—
Other Non-cash Expenses		566			41
Changes in operating assets and liabilities
Accounts Receivable		(342	)		7,229
Taxes Receivable		2,001			163
Inventory, Prepaid Expenses and Other Assets		336			52
Accounts Payable and Accrued Liabilities		41,478			(1,484	)
Other Assets and Liabilities		(147	)		(1,104	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		31,111			23,310
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		16,384			24,513
Acquisitions of Undeveloped Acreage		(871	)		(1,783	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(100,136	)		(54,004	)
NET CASH USED IN INVESTING ACTIVITIES		(84,623	)		(31,274	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts		69,846			171,000
Proceeds from Debtor-In-Possession Financing		35,000			—
Repayments of Long-Term Debt and Line of Credit		—			(145,170	)
Repayments of Loans and Other Notes Payable		(945	)		(319	)
Reorganization Item - Debtor-In-Possession Financing Fee		(3,750	)
Debt Issuance Costs		—			(7,791	)
Payment of Preferred Dividends in Arrears		—			(598	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		100,151			17,122
Net Increase in Cash, Cash Equivalents and Restricted Cash		46,639			9,158
Beginning Cash, Cash Equivalents and Restricted Cash		15,247			3,697
Ending Cash, Cash Equivalents and Restricted Cash	$	61,886		$	12,855
SUPPLEMENTAL DISCLOSURES
Cash and Cash Equivalents	$	28,780		$	12,855
Restricted Cash required to collateralize Letters of Credit (See Note 13)		33,106			—
Total Ending Cash, Cash Equivalents and Restricted Cash	$	61,886		$	12,855

Interest Paid, net of capitalized interest	$	11,965		$	8,494
Cash Received for Income Taxes		(2,001	)		(163	)

NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin	$	729		$	(1,893	)
Proceeds held in Escrow - non-cash component of Gain on Sale of Assets		150			5,000
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures		(30,943	)		1,652
Increase Long Term Debt - Equipment Financing		345			607
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		—			(879	)
Decrease in Bond Interest Payable due to Debt to Equity Conversions		—			(12	)
Increase in Common Stock outstanding due to Debt to Equity Conversions		—			467

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent natural gas, NGL and condensate company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in natural gas, NGL and condensate properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

The interim Consolidated Financial Statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Actual results may differ from those estimates and results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in prices for natural gas, NGLs and crude oil, future impact of financial derivative instruments, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market consumption, interruption in production, our ability to obtain additional capital, and the success of natural gas, NGL and oil recovery techniques.

Certain amounts and disclosures have been condensed or omitted from these Consolidated Financial Statements pursuant to the rules and regulations of the Securities and Exchange Commission. Therefore, these interim financial statements should be read in conjunction with the audited Consolidated Financial Statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017.

Subsequent to the sale of our Illinois Basin operations in 2016, our subsidiaries Rex Energy IV, LLC and Penntex Resources Illinois, Inc. were dormant entities with no assets or operations. Effective April 10, 2018, we consolidated Rex Energy IV, LLC and Penntex Resources Illinois, Inc. by way of a merger with and into Rex Energy I, LLC.

On May 18, 2018 (the “Petition Date”), the Company and certain of its direct subsidiaries (collectively with the Company, the “Rex Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Western District of Pennsylvania (“Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Debtors will operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The consolidated financial statements have been prepared as if we are a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization Items, Net” on our consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “Liabilities Subject to Compromise” on our consolidated balance sheet at June 30, 2018. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on shareholders’ deficit accounts of any changes that may be made to our capitalization; or (iv) the effect on operations of any changes that may be made to our business. While operating as debtors-in-possession under Chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization (a “Plan”) could materially change the amounts and classifications on our historical consolidated financial statements.

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of natural gas, NGLs, and oil future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

On the Petition Date, the Rex Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Rex Debtors’ Chapter 11 cases are being administered jointly under the caption In re R.E. Gas Development, LLC, et al., Case No. 18-22032.

The Rex Debtors are operating their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted certain relief requested by the Rex Debtors, allowing us to use our cash to fund the Chapter 11 proceedings, pursuant to an agreement with the first lien lenders, and giving us the authority to, among other things, continue to pay employee wages and benefits without interruption, to u tilize our current cash management system and to make royalty payments. During the pendency of the Chapter 11 proceedings, all transactions outside the ordinary course of our business require prior approval of the Bankruptcy Court. For goods and services p rovided following the Petition Date, we intend to pay vendors in full under normal terms.

In order to exit Chapter 11 successfully, the Rex Debtors will need to obtain confirmation by the Bankruptcy Court of a Plan that satisfies the requirements of the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a proposed Plan (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the resolution of the outstanding claims against and interests in the Debtors pursuant to the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a related proposed disclosure statement (as may be amended, modified or supplemented from time to time, the “Proposed Disclosure Statement”). In addition to being voted on by holders of impaired claims and equity interests, the Proposed Plan must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. If accepted by holders of impaired claims and equity interests, the Proposed Plan would, among other things, resolve the Debtors’ prepetition obligations, and set forth the revised capital structure of the newly reorganized entity, unless all or substantially all of the Debtors' assets are sold during the Chapter 11 proceedings. The Debtors will seek approval of the Proposed Disclosure Statement on August 23, 2018, and, if obtained, will solicit votes on the Proposed Plan.

Under certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm the Proposed Plan even if it has not been accepted by all impaired classes of claims and equity interests. The precise requirements and evidentiary showing for confirming a Plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., unsecured or secured claims, subordinated or senior claims). Generally, with respect to equity shares, a Plan may be “crammed down” even if the shareholders receive no recovery if the proponent of the Plan demonstrates that (1) no class junior to the equity shares are receiving or retaining property under the Plan and (2) no class of claims or interests senior to the equity shares are being paid more than in full.

On June 1, 2018, the Rex Debtors filed with the Bankruptcy Court a Motion For Orders Pursuant To Section 363 of the Bankruptcy Code: (I)(A) Approving Bidding Procedures For The Sale Of The Debtors’ Assets, (B) Scheduling An Auction And Approving The Form And Manner Of Notice Thereof, (C) Approving Assumption And Assignment Procedures and (D) Scheduling A Sale Hearing And Approving The Form And Manner Of Notice Thereof; (II)(A) Approving The Sale Of The Debtors’ Assets Free And Clear Of Liens, Claims, Interests And Encumbrances and (B) Approving The Assumption And Assignment Of Executory Contracts And Unexpired Leases; and (III) Granting Related Relief. On June 29, 2018, the Bankruptcy Court entered an order approving the bidding procedures and scheduling the auction.

We have been in discussions with various third parties who may be interested in purchasing some or all of the assets of the Rex Debtors through the bankruptcy process, either through a sale pursuant to Section 363 of Chapter 11 of the Bankruptcy Code or in connection with the Proposed Plan. At this time, it is not possible to predict accurately the effect of the Chapter 11 reorganization process on our business, creditors or stockholders, when the Rex Debtors may emerge from Chapter 11 or what the disposition will be of any claims against the Rex Debtors. Our future results depend on the timely and successful confirmation and implementation of the Proposed Plan.

Copies of all court filings made in our Chapter 11 cases are available from Prime Clerk, Claims and Noticing Agent for the bankruptcy proceedings, at https://cases.primeclerk.com/rexenergy/Home-Index.

On July 2, 2018, the Rex Debtors filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Rex Debtors, subject to the assumptions filed in connection therewith. On August 1, 2018, the Debtors filed amended schedules and statements. The schedules and statements may be subject to further amendment or modification after filing. Holders of prepetition claims will be required to file proofs of claims by the applicable deadline for filing certain proofs of claims in the Rex Debtors’ Chapter 11 cases. The court has set August 6, 2018 as the bar date for filing of general claims, and November 14, 2018 as the bar date for filing of governmental claims. Differences between amounts scheduled by the Rex Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process.

Our consolidated balance sheet includes amounts classified as “Liabilities Subject to Compromise,” which represent prepetition liabilities that have been allowed, or that we anticipate will be allowed, as claims in our Chapter 11 cases. The amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet:

We have incurred and are expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect our results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. The following table summarizes the components of reorganization items included on the consolidated statements of operations:

^(a) Acceleration of deferred gains on debt restructurings, deferred financing costs and unamortized net discounts for debt instruments previously accounted for as troubled debt restructurings pursuant to ASC 470-60, Troubled Debt Restructurings by Debtors.

Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Rex Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Rex Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Creditors are stayed from taking any actions against the Rex Debtors as a result of defaults on the Rex Debtors’ debt obligations (which defaults were triggered prior to or by the filing of Bankruptcy Petitions), subject to certain limited exceptions permitted by the Bankruptcy Code. We did not record interest expense on our 1%/8% senior secured second lien notes (“Second Lien Notes”) or our unsecured 6.25% Senior Notes due 2022 and unsecured 8.875% Senior Notes due 2020 (the “Unsecured Notes”) for the period from May 18, 2018 (Petition Date), through June 30, 2018. For that period, contractual interest on the Second Lien Notes and the Unsecured Notes was approximately $5.7 million.

Generally, under the Bankruptcy Code, prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our existing common and preferred shares are entitled to receive any settlement or retain any property under a Plan. The ultimate recovery to creditors and/or shareholders, if any, will not be determined until confirmation and implementation of one or more Plans. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 proceedings to each of these constituencies or what types or amounts of settlements, if any, they will receive. A Plan could result in holders of the Rex Debtors’ liabilities and/or equity shares receiving no settlement on account of their interests and cancellation of their holdings.

On May 29, 2018, the Bankruptcy Court appointed the official committee for unsecured creditors (the “UCC”). The UCC and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Rex Debtors.

Subject to certain exceptions, under the Bankruptcy Code, the Rex Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Rex Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Rex Debtor’s estate for damages. Generally, the assumption of an executory contract or unexpired lease requires the Rex Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with any of the Rex Debtors in this Quarterly Report on Form 10-Q, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the applicable Rex Debtor, is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Rex Debtors expressly preserve all of their rights with respect thereto.

Our filing of the Bankruptcy Petitions constituted an event of default under our Term Loan Credit Facility, and the indentures governing the Second Lien Notes and the Unsecured Notes, which resulted in automatic acceleration of our obligations under those instruments. However, our outstanding obligations under the Term Loan Credit Facility and the indentures governing the Unsecured Notes were accelerated prior to the Petition Date. In addition to the non-payment of second lien interest, we also encountered additional events of default related to certain non-financial covenants associated with our term loan agreement. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and written notices of the events of default in a subsequent draw request under the term loan agreement. Additionally, other events of default have occurred, including the receipt of a going concern explanatory paragraph from our independent registered public accounting firm on our consolidated financial statements for the year ended December 31, 2017. We received a notice of acceleration on April 27, 2018, from the lenders under our term loan agreement demanding immediate payment of all outstanding notes and loans, together with all accrued interest, fees, yield maintenance and call protection amounts. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against us as a result of an event of default. See Note 8 “Debt” for additional details regarding our debt.

The significant risks and uncertainties related to our covenant violations, liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We adopted this standard effective January 1, 2018 on a retrospective basis. Adoption of the standard did not have an impact on the presentation of our consolidated statements of cash flows

In May 2017, the FASB issued ASU 2017-09, Stock Compensation - Scope of Modification Accounting, which provides guidance about the types of changes to terms or conditions of a share-based payment award that would require an entity to apply modification accounting. The new guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The amendments in this update should be applied prospectively to awards modified on or after the adoption date. We adopted this standard effective January 1, 2018. Adoption of the standard did not have a material impact on our consolidated financial statements.

Effective January 1, 2018, we adopted Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, we recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that would result in a material impact to its consolidated financial statements. We also implemented processes and controls to ensure new contracts are reviewed for the appropriate accounting treatment and to generate the required disclosures under the standards.

Revenue from operations is derived from sales of natural gas, NGL and condensate products produced by our well properties for which we are the operator. A de minimis percentage of revenue is also earned from either working interests, royalty interests, or small override interests we hold in various non-operated well properties. Our sales revenue is generated from on-going daily or monthly sales of volumes of gas and oil commodities, the sales volumes determined by metering or other measurement methods at the delivery point when control of the commodities transfers to the customer.

We recognize sales of our natural gas, NGL and condensate products when control of the product is transferred to the customer at delivery points specified in each commodity purchase contract. Under our commodity sales contracts, the delivery of each unit of natural gas, NGLs or condensate represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There are no significant financing components associated with our revenues from sales to customers as payment terms are typically within 30 to 60 days of control transfer. Sales revenue recognized corresponds directly with the value to the customer of our performance completed to date. We record revenue from sales of our natural gas, NGL and condensate production in the amount equal to our net revenue interest in sales from the producing properties. Under ASC 606, we recognize revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. We consider risk of loss an important indicator of when control transfers, which is comprised of risks associated with loss of product during processing. We concluded that title, custody, and acceptance are not by themselves determinative indicators of control, as such factors may be present in the case of a sale or the performance of a service.

As a result of this analysis, we concluded that the Company represents the principal and the ultimate third party is its customer, which implies that the Company maintains control of the product through the tailgate of gas processing plants in certain natural gas processing in accordance with the control model in ASC 606. As a result, there were no changes to our presentation of revenues and expenses for these agreements.

Our natural gas production is primarily sold under contracts that are typically priced at a differential to published commodity index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. NGL and condensate production is sold under contract pricing referenced to various liquids commodity index prices. All revenue from production is generated from our operations in the Appalachian Basin.

We use the sales method to account for natural gas production imbalances. If our sales volume for a well exceeds our proportionate share of production from the well, a liability is recognized to the extent that our share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which we have taken less than our proportionate share of production.

Under our product sales contracts, our customers are invoiced once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to material contract assets or contract liabilities.

Our contracts with customers represent a series of performance obligations satisfied over time when a performance obligation is satisfied by the transfer of control over a product to the customer. The transfer of control is generally considered to occur when we have transferred custody, title, risk of loss and relinquished any repurchase rights or other similar rights. Our commodity sales contracts are established to facilitate on-going sales of our products with our customers over the term of the contract, with pricing and delivery terms identified in each contract. We do not have contracts with customers that describe the performance obligation in terms of a defined gross total delivery volume over time. We utilized the practical expedient in ASC 606-10-50-14(A) which states that disclosure of the portion of a transaction price allocated to remaining performance obligations is not required if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, each unit of product generally represents a separate performance obligation; therefore future sales volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

As of June 30, 2018 and December 31, 2017, we had trade receivable balances related to revenue from contracts with customers of approximately $25.9 million and $21.7 million, respectively.

The following table summarizes our disaggregated revenues recognized from contracts with customers in our Consolidated Statements of Operations for the three and six month periods ended June 30, 2018 and 2017.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2018. BSP has paid for its interest in the elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended June 30, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of June 30, 2018, all 45 committed wells were in line and producing.

The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

On January 11, 2017, we, together with MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation. These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to us, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us was held in escrow and released to us in December 2017. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the additional proceeds held in escrow. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down amounts outstanding under our prior revolving line of credit and for general corporate purposes.

On March 13, 2018, we entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which we agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to us. In a related transaction, we entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which we agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018, prior to closing adjustments. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded future abandonment cost changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Accretion expense totaled $0.2 million and $0.5 million for the three and six months ended June 30, 2018, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively. These amounts are recorded as depreciation, depletion, amortization, and accretion expense on our Consolidated Statements of Operations. We account for future abandonment costs that relate to wells that are drilled jointly based on our working interest in those wells.

¹ Includes approximately $1.0 million of short-term future abandonment costs, which are classified as Accrued Liabilities on our Consolidated Balance Sheet.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparties to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions (see Note 8, Debt, to our Consolidated Financial Statements). We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled cash settlement date. For additional information, see Note 9, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. For the six months ended June 30, 2018, approximately 98.9% of our commodity sales came from five purchasers, with the largest single purchaser accounting for 62.1% of commodity sales. We believe the growth in our Appalachian estimated proved reserves, as well as the quantity of purchasers, will help us to minimize our future risks by diversifying our ratio of condensate and gas sales.

On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility were used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. We cash collateralized our outstanding letters of credit during the second quarter of 2018 in the amount of approximately $33.1 million. The maximum commitments of the lenders under the Term Loan were initially limited to $300,000,000. Subsequent to certain events of default under the Term Loan, we were limited to drawing approximately $261.3 million, inclusive of amounts drawn to cash collateralize the letters of credit. As of June 30, 2018, we had approximately $228.2 million in borrowings outstanding and approximately $33.1 million in outstanding cash collateralized letters of credit.

Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan were subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount (the “Make Whole Amount”). Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at June 30, 2018 they have been recorded at their fair value using Level 2 inputs. At March 31, 2018, we had recorded a fair value liability of approximately $53.0 million as Short-Term Derivative Instruments on our Consolidated Balance Sheet. During the second quarter of 2018, the Make Whole Amount became due and payable as a result of certain events of default and the subsequent acceleration of debt. As of June 30, 2018, the Make Whole Amount of $50 million, as referenced in the Restructuring Support Agreement, has been recorded in Accounts Payable on our Consolidated Balance Sheet. For the six months ended June 30, 2018, we have recorded a realized loss on derivatives of $50.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, that led to the Chapter 11 Bankruptcy filing. As of December 31, 2017, the fair value of these embedded derivatives was not material.

On May 23, 2018, we executed a senior-secured debtor-in-possession term loan agreement (“DIP Facility”) with AGES, as administrative agent, AGES, as collateral agent , Macquarie Bank Limited, as issuing bank and the lenders from time to time party thereto. The DIP Facility has a maturity date of November 18, 2018. In accordance with the final court order approving the DIP Facility dated July 11, 2018, the DIP Facility effectively consolidates our prior Term Loan balances of $261.3 million, the Make-Whole Amount of $50.0 million and additional borrowing capacity of $100.0 million (the “Additional Capacity”). As of June 30, 2018, we had $35.0 million in outstanding Additional Capacity borrowings under the DIP Facility which we incurred as interim financing approved by the Bankruptcy Court. Borrowings under the DIP Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. Upon the occurrence and continuance of an event of default under the DIP Facility, all outstanding loans bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable in arrears on the last business day of each March, June, September and December. Interest on the Make-Whole Amount accrues from July 11, 2018 until the maturity date. Under the DIP Facility, we paid a $3.8 million up-front commitment fee which we expensed to Reorganization Items, net on our Statement of Operations. Additionally, we have agreed to pay an unused commitment fee of 3.25% on the average daily unused amount of the DIP Facility. The DIP Facility contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The DIP Facility also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after June 30, 2018, the PDP Coverage Ratio (as defined in the DIP Facility) will not be less than 1.25 to 1.00; (2) our liquidity at all times must be greater than $10.0 million, and (3) each Friday we are required to submit budget variance reports showing that (i) aggregated receipts are not less than 85% of budgeted receipts, (ii) aggregated disbursements, other than capital expenditures, are not greater than 115% of budgeted disbursements and (iii) actual capital expenditures are not greater than 105% of budgeted capital expenditures. As of June 30, 2018, our PDP Coverage Ratio was 1.85 to 1.00 and our liquidity was approximately $88.8 million. To date we have complied with all budget variance testing covenants.

Obligations under the DIP Facility are secured by a perfected first priority lien and a perfected junior lien on, and security interest in, all present and after-acquired property not subject to a valid, perfected and non-avoidable lien or security interest in existence on the Petition Date or to a valid lien in existence on the Petition Date that is perfected subsequent to the Petition Date as permitted by Bankruptcy Code Section 546(b). Obligations under the DIP Facility are also secured by a perfected first priority priming lien on, and security interest in, all prepetition collateral.

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”; the Existing Notes, together with the Second Lien Notes are collectively referred to herein as the “Senior Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Second Lien Notes and (ii) 10.1 million shares of our common stock (the “Shares”). Subsequent to the Exchange, we had a total of $12.7 million of Existing Notes and $587.6 million of Second Lien Notes. We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain was recognized within our GAAP basis financial statements and a new effective interest rate was established.

Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016, with certain holders of our Existing Notes, as well as holders of our Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.4 million shares of unrestricted common stock during the year ended December 31, 2016. During the year ended December 31, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain for the three months ended March 31, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. The Indentures also contain customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The trustee under the Indenture governing the Existing Notes declared the Existing Notes immediately due and payable on May 3, 2018. Our obligations under the Indenture governing the Second Lien Notes was automatically accelerated at the time of the filing of the Bankruptcy Petitions.

Interest is payable on our Second Lien Notes at a rate of 8.0% per annum on April 1 and October 1 of each year. We have not made the semi-annual interest payment to the holders of our Second Lien Notes that was due on April 2, 2018, and did not make the interest payment prior to the expiration of the 30 day grace period. On May 18, 2018, we ceased accruing interest on the Second Lien Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Second Lien Notes for the period of May 18, 2018 through June 30, 2018 is approximately $5.6 million. As of June 30, 2018, we had approximately $29.6 million of accrued interest related to the Second Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet.

Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is payable at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is payable at a rate of 6.25% per annum on February 1 and August 1 of each year. On May 18, 2018, we ceased accruing interest on the Existing Notes in accordance with the provisions of ASC 852. Contractual interest that we have not accrued for the Existing Notes for the period May 18, 2018 through June 30, 2018 is approximately $0.1 million. As of June 30, 2018, we had approximately $0.4 million of accrued interest related to the Existing NotesSecond Lien Notes recorded in the Accrued Interest Payable component of our Liabilities Subject to Compromise balances on our Consolidated Balance Sheet.

As of December 31, 2017, we had recorded on our Consolidated Balance Sheet approximately $50.1 million of deferred gain on debt restructurings related to the Senior Notes. During the second quarter of 2018, in accordance with ASC 852 and in conjunction with the filing of our Bankruptcy Petition, we adjusted the carrying value of the Senior Notes to equal the outstanding principal due on the notes, plus interest that had been accrued up to May 18, 2018, (Petition Date). Adjusting the carrying value of the Senior Notes resulted in recognition of the remaining unamortized portion of the deferred gain on debt restructurings in the amount of approximately $43.6 million in Reorganization Items, Net, in our Consolidated Statement of Operations.

The weighted average interest rate on borrowed balances under the DIP Facility and the Term Loan for the three and six months ended June 30, 2018 was approximately 12.0% and 11.0%, respectively. The average interest rate on our capital leases for the three and six months ended June 30, 2018 was approximately 16.5% and 16.8%, respectively.

			December 31, 2017
			Principal		Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Deferred Gain on Debt Restructurings, Net			Net Carrying Value

Term Loans, Net
	Term Loan Draw - due April 2020		$	189,500	$	(4,711	)	$	(2,761	)	$	—		$	182,028

Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333	$	—		$	—		$	(60	)	$	7,273
	6.25% Senior Notes due 2022			5,363		—			—			(67	)		5,296
	1% / 8% Second Lien Senior Notes due 2020			587,606		—			—			50,196			637,802
			$	600,302	$	—		$	—		$	50,069		$	650,371

Other Long-Term Debt
	Long-Term Capital Leases and Other Notes Payable- Equipment Financing
		Due March, 2021												$	632
		Due June, 2021													1,418
		Due September, 2021													1,578
		Due May 2022													6,454
		Total Capital Lease Obligations												$	10,082
		Less: Current Portion of Capital Leases and Other Notes Payable													(1,926	)
														$	8,156

As of December 31, 2017, the Deferred Gain on Debt Restructurings, Net includes Unamortized Premiums/Discounts of $14.0 million, Unamortized Debt Issuance Costs of $33.6 million and Unamortized Deferred Gain on Debt Restructurings of $30.4 million.

Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into natural gas, NGL and oil commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of June 30, 2018 and December 31, 2017, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations.

We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with these counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Expense. We paid net cash settlements of $4.9 million and $6.9 million in relation to our commodity derivatives during the three and six months ended June 30, 2018, respectively and paid net cash settlements of $2.1 million and $5.5 million in relation to our commodity derivatives during the three and six months ended June 30, 2017, respectively.

We entered into the Term Loan in April 2017, which included certain call protection and yield maintenance provisions that require accelerated payments upon certain events. Prepayments (including mandatory prepayments), terminations, certain events of default, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount.

Some of the provisions are required to be bifurcated from the Term Loan and valued separately as derivatives. Due to the short-term nature of these amounts at March 31, 2018 they have been recorded at their fair value using Level 2 inputs. As of June 30, 2018, we have recorded a fair value liability of approximately $50.0 million as Current Liability on our Consolidated Balance Sheet. For the six months ended June 30, 2018, we recorded a loss of approximately $50.0 million as Gain (Loss) on Derivatives, Net in the Consolidated Statement of Operations in connection with various events occurring during the first quarter, which led to our decision to file the Bankruptcy Petitions. As of December 31, 2017, the fair value of these embedded derivatives was not material.

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets as defined in the contract are achieved at specified future dates. We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument, as prescribed in ASC 815-10-15-83. We recorded the contract at its initial fair value of approximately $1.2 million as additional consideration in the calculation of the gain on the sale of the assets. Fair value was determined through application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes June 30, 2019. As of June 30, 2018 and December 31, 2017, the contingent consideration contract was valued at $2.5 million and $1.7 million, respectively. For the three month period ended June 30, 2018, the average index price for oil as specified in the contract was in excess of the required threshold price for the quarter, and we recognized income of approximately $0.8 million, representing the discounted fair value of the additional consideration earned during the quarter. The contract stipulates that the buyer will remit to us $0.9 million not later than July 15, 2019, for the consideration earned during the three months ended June 30, 2018. The discounted fair value of approximately $0.8 million is included in Accounts Receivable on our Consolidated Balance Sheets as of June 30, 2018.

On May 18, 2018, the Bankruptcy Court approved a motion to continue our derivative programs in the normal course of business. In conjunction with the Bankruptcy Petitions, one of our derivative counterparties elected to terminate their outstanding contracts with us, resulting in a $2.0 million liability. Approximately $0.8 million was related to the fair value of the derivatives on the date of termination, which was recognized as (Loss) Gain on Derivatives, Net for the three and six months ended June 30, 2018. Approximately $1.2 million was related to costs associated with the early termination of the derivative positions and was recorded as Reorganization Items, Net for the three and six months ended June 30, 2018.

The following table summarizes the location and amounts of gains and losses on our derivative instruments, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017:

Our derivative instruments are recorded on the balance sheet as either an asset or a liability, in either case measured at fair value. The fair value associated with our derivative instruments was a net liability of approximately $24.9 million and approximately $19.4 million at June 30, 2018 and December 31, 2017, respectively.

Our open asset/(liability) financial commodity derivative instrument positions at June 30, 2018 consisted of:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		85,750	Bbls	$	—	$	—	$	—	$	57.47		$	(817	)
2018 - Three-Way Collars		42,000	Bbls		41.82		51.09		60.75		—			(413	)
2019 - Swaps		118,000	Bbls		—		—		—		55.89			(1,231	)
2019 - Collars		18,000	Bbls		—		45.00		55.80		—			(125	)
2019 - Three-Way Collars		42,000	Bbls		38.57		48.57		58.86		—			(375	)
2020 - Swaps		24,000	Bbls		—		—		—		51.00			(304	)
2020 - Collars		22,500	Bbls				45.00		55.80					(167	)
2020 - Three-Way Collars		21,500	Bbls		38.95		48.95		60.22		—			(103	)
2021 - Swaps		6,000	Bbls		—		—		—		51.00			(76	)
2021 - Collars		16,500	Bbls		—		45.00		55.80		—			(125	)
2021 - Three-Way Collars		62,500	Bbls		37.44		47.04		57.98		—			(240	)
2022 - Three-Way Collars		23,000	Bbls		39.35		49.35		60.43		—			(60	)
		481,750	Bbls										$	(4,037	)
Natural Gas
2018 - Swaps		12,127,500	Mcf		—		—		—		2.98		$	394
2018 - Three-Way Collars		4,260,000	Mcf		2.31		2.88		3.55		—			310
2018 - Calls		2,920,000	Mcf		—		—		3.97		—			(19	)
2018 - Collars		2,222,500	Mcf		—		2.60		3.04		—			(134	)
2018 - Basis Swaps - Dominion South		9,808,000	Mcf		—		—		—		(0.83	)		(1,858	)
2018 - Basis Swaps - Texas Gas		7,360,000	Mcf		—		—		—		(0.13	)		324
2019 - Swaps		7,500,000	Mcf		—		—		—		2.91			129
2019 - Three-Way Collars		8,045,000	Mcf		2.35		2.81		3.43		—			313
2019 - Collars		4,471,750	Mcf		—		2.62		3.03		—			(227	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,725	)
2020 - Swaps		4,642,500	Mcf		—		—		—		2.90			242
2020 - Three-Way Collars		4,935,000	Mcf		2.33		2.77		3.31		—			350
2020 - Collars		2,645,000	Mcf		—		2.65		3.03		—			(34	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(2,068	)
2021 - Swaps		900,000	Mcf		—		—		—		2.90			59
2021 - Three-Way Collars		1,346,250	Mcf		2.32		2.74		3.20		—			97
2021 - Collars		792,500	Mcf		—		2.65		3.05		—			43
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2022 - Collars		147,500	Mcf		—		2.65		3.05		—			11
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
		108,818,500	Mcf										$	(6,533	)
NGLs
2018 - C3+ NGL Swaps		640,036	Bbls		—		—		—		33.06		$	(8,150	)
2018 - Ethane Swaps		780,000	Bbls		—		—		—		12.13			(450	)
2019 - C3+ NGL Swaps		570,814	Bbls		—		—		—		30.90			(4,524	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(964	)
2019 - Ethane Swaps		1,264,750	Bbls		—		—		—		12.60			322
2020 - C3+ NGL Swaps		191,112	Bbls		—		—		—		32.22			(1,875	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(241	)
2020 - Ethane Swaps		1,007,750	Bbls		—		—		—		12.31			(73	)
2021 - C3+ NGL Swap		88,404	Bbls		—		—		—		41.70			(599	)
2021 - Ethane Swaps		724,000	Bbls		—		—		—		12.27			(98	)
2022 - C3+ NGL Swap		9,420	Bbls		—		—		—		50.50			(33	)
2022 - Ethane Swaps		352,250	Bbls		—		—		—		12.27			(107	)
		5,769,836	Bbls										$	(16,791	)

The combined fair value of derivatives, none of which are designated or qualifying as hedges, included in our Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017 is summarized below:

	June 30,			December 31,
($ in Thousands)	2018			2017
Short-Term Derivative Assets:
NGL—Swaps	$	365		$	928
Natural Gas—Swaps		1,118			3,734
Natural Gas—Collars		22			183
Natural Gas—Basis Swaps		328			191
Natural Gas—Three-Way Collars		513			1,721
Contingent Consideration - Sale of Illinois Basin		2,450			1,251
Total Short-Term Derivative Assets	$	4,796		$	8,008
Long-Term Derivative Assets:
NGL—Swaps	$	308		$	409
Natural Gas—Swaps		422			411
Natural Gas—Collars		119			—
Natural Gas—Three-Way Collars		614			429
Contingent Consideration - Sale of Illinois Basin		—			470
Total Long-Term Derivative Assets	$	1,463		$	1,719
Total Derivative Assets	$	6,259		$	9,727
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(42	)	$	(31	)
Crude Oil—Three-Way Collars		(650	)		(92	)
Crude Oil—Swaps		(1,442	)		(518	)
NGL—Swaps		(11,700	)		(10,281	)
NGL—Collars		(482	)		—
Natural Gas—Three-Way Collars		(56	)		(49	)
Natural Gas—Collars		(268	)		(146	)
Natural Gas—Basis Swaps		(3,725	)		(3,621	)
Natural Gas—Call		(19	)		(154	)
Natural Gas—Swaps		(711	)		—
Total Short - Term Derivative Liabilities	$	(19,095	)	$	(14,892	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(541	)	$	(161	)
Crude Oil—Swaps		(986	)		(202	)
Crude Oil—Collars		(376	)		(425	)
NGL—Swaps		(4,560	)		(4,482	)
NGL—Collars		(723	)		(385	)
NGL—Three Way Collars		—			(66	)
Natural Gas—Swaps		(5	)		(423	)
Natural Gas—Basis Swaps		(4,671	)		(7,120	)
Natural Gas—Collars		(213	)		(713	)
Natural Gas—Three-Way Collars		—			(272	)
Total Long-Term Derivative Liabilities	$	(12,075	)	$	(14,249	)
Total Derivative Liabilities	$	(31,170	)	$	(29,141	)

Fair value is 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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Our Level 2 fair value measurements are composed of our derivative contracts and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, probability factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of June 30, 2018 and December 31, 2017 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the three and six months ended June 30, 2018 and for the year ended December 31, 2017 there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are composed of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair values attributable to our oil derivatives as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are composed of swap, collars, swaption, three way collar, basis swap, cap swap, call and put spread contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are composed of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of June 30, 2018 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Future Abandonment Costs, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 1 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

During the six months ended June 30, 2018 and 2017, we recorded other than temporary impairments of $12.5 million and $4.6 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment of proved properties. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. The inputs used in determining fair value as a part of the impairment expense calculation are considered to be Level 3 within the fair value hierarchy. Impairment considerations for unproved properties include future development plans for the leases, remaining months on the lease’s primary term, and market value for similar acreage in the area. For additional information on our impairment expense, see Note 15, Impairment Expense, to our Consolidated Financial Statements.

We recognize deferred income taxes for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.

Management estimates the annual effective income tax rate quarterly, based on current annual forecasted results. Items unrelated to current year ordinary income are recognized entirely in the period identified as a discrete item of tax. The quarterly income tax provision is composed of tax on ordinary income provided at the most recent estimated annual effective tax rate, adjusted for the tax effect of these discrete items.

For the six months ended June 30, 2018, the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 21.0% primarily due to the effect of maintaining a full valuation allowance against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period.

For the six months ended June 30, 2017 the estimated annual effective tax rate applied to ordinary losses from operations was 0.0%. The estimated annual effective tax rate differs from the U.S. statutory rate of 35.0% primarily due to the effect of maintaining a full valuation allowances against our deferred tax assets. Discrete period tax expense was not material and is also offset by a full valuation allowance resulting in zero tax expense for the period.

No income tax payments were made for the six months ended June 30, 2018. Income tax payments made during the six months ended June 30, 2017 were $2.0 million. Tax refunds received during the six months ended June 30, 2018 were approximately $2.0 million, and refunds received during the six months ended June 30, 2017 were approximately $0.2 million.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed the Internal Revenue Code, reducing the Federal statutory corporate income tax rate from 35% to 21%, allowing for bonus depreciation on certain qualified property, eliminating the alternative minimum tax for corporate taxpayers, adding new limitations on the deductibility of business interest expense deduction for net operating losses. The Tax Act also authorizes the Treasury Department to issue regulations with respect to the new provisions. We are still in the process of fully analyzing the Tax Cuts and Jobs Act and its effects on the Company. We cannot predict how the changes in the Tax Cuts and Jobs Act, regulations, or other guidance issued under it or conforming or non-conforming state tax rules might affect us or our business. In addition, there can be no assurance that U.S. tax laws, including the corporate income tax rate, will not undergo significant changes in the near future.

On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department (the “Staff”) of The Nasdaq Stock Market LLC (“Nasdaq”) indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we request an appeal before the Nasdaq Hearings Panel (the “Panel”). We did not appeal this determination. Nasdaq filed a Form 25-NSE on April 19, 2018. Following the delisting of our common stock from Nasdaq, our common stock has been quoted on the OTC Markets Group’s Pink marketplace.

As discussed in Note 1, Basis of Presentation and Principles of Consolidation, references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. As of June 30, 2018, we have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of June 30, 2018 and December 31, 2017, shares of common stock issued and outstanding totaled 10,707,788 and 10,244,394, respectively. During the six months ended June 30, 2017, we issued approximately 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. See Note 8, Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

As of both June 30, 2018 and December 31, 2017, 3,987 shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), were issued and outstanding.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. Dividends of $1.8 million were declared by our Board of Directors in 2017, bringing dividends in arrears current through August 15, 2016. Dividends declared and paid in 2017 were composed of cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2016 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of our common stock. On February 15, 2018 , we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of August 15, 2016 to November 15, 2016, which was paid in shares of our common stock; as of June 30, 2018, no additional dividends have been paid on the Series A Preferred Stock in 2018. As of June 30, 2018, accumulated dividends in arrears totaled $3.6 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulation of unpaid dividends during the current reporting period is included in our Net Income (Loss) in the determination of Net Income (Loss) Attributable to Common Shareholders and related earnings per share calculations.

If dividends are in arrears and unpaid for six or more quarterly periods (whether or not consecutive), the holders of the shares of Series A Preferred Stock will have the right to elect two additional directors to serve on our board of directors. We did not make the dividend payment due on May 15, 2018, which resulted in a total of six quarterly dividend payments in arrears.

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals one vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as cash flows from financing activities, rather than as cash flows from operating activities.

During the six months ended June 30, 2018 and 2017, no new options to purchase shares of our common stock were granted. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended June 30, 2018 was negligible. Stock-based compensation expense from operations relating to stock options outstanding for the three and six months ended June 30, 2017 was $0.1 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative Expense. There were no stock options exercised during the six months ended June 30, 2018. There was no tax benefit related to stock option exercises for each of the six-month periods ended June 30, 2018 and 2017.

A summary of the status of our issued and outstanding stock options as of June 30, 2018 is as follows:

The weighted average remaining contractual term for options outstanding at June 30, 2018 was 4.4 years and there was no aggregate intrinsic value. The weighted average remaining contractual term for options exercisable at June 30, 2018 was 4.3 years and there was no aggregate intrinsic value. As of June 30, 2018, unrecognized compensation expense related to stock options was negligible.

During the six-month period ended June 30, 2018, there were no issuances of restricted common stock to employees. During the six-month period ended June 30, 2017, the Compensation Committee approved the issuance of an aggregate of 101,237 shares of restricted stock to 28 employees. Certain of our outstanding restricted stock awards granted in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group over a three-year period.

The weighted average fair value of the TSR awards granted as of December 31, 2015 was $2.56 per share. There have been no TSR awards granted subsequent to December 31, 2015. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:

Compensation expense from restricted stock awards associated with our operations was $0.1 million and $1.2 million for the three and six months ended June 30, 2018, respectively and it was $0.4 million and $0.4 million for the three and six months ended June 30, 2017, respectively. During the three months ended March 31, 2018, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2018. This waiver resulted in the vesting of approximately 29,411 restricted stock awards with associated expense of approximately $0.9 million. During the six months ended June 30, 2017, 179,519 performance stock awards were forfeited due to not meeting specified targets, which resulted in a net reversal of prior compensation expense of approximately $0.1 million. As of June 30, 2018, total unrecognized compensation cost related to restricted common stock grants was approximately $0.3 million, which will be recognized over a weighted average period of 1.2 years.

A summary of the restricted stock activity for the six months ended June 30, 2018 is as follows:

Subsequent to the Petition Date, the Bankruptcy Court approved motions to implement a Key Employee Retention Plan (“KERP”) and a Key Executive Incentive Plan (“KEIP”). The KERP is designed as a retention tool for key employees that will pay a fixed amount of $132,500 per quarter, for a total of three quarters, beginning on or about June 30, 2018. Amounts related to the KERP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as Reorganization Items, net on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.1 million accrued related to the KERP.

The KEIP is designed to incentivize our key executives to maximize value for the benefit of all of our stakeholders through the measurement period of May 2018 through December 2018. A portion of the payout of the KEIP is dependent on the achievement of certain performance goals, including production, lease operating expenses, and safety goals. A separate portion of the payout of the KEIP is dependent on the achievement of certain milestones for the emergence from bankruptcy through a successful plan of reorganization or closing of a sale of substantially all of the assets within certain specified timeframes. The total amount of compensation available under the KEIP plan is dependent on the level of operating performance and successful emergence from bankruptcy and range from approximately $1.2 million up to a maximum of $3.5 million in total. Amounts under the KEIP are accounted for as Accrued Expenses on our Consolidated Balance Sheet and expensed as General and Administrative Expense on our Consolidated Statement of Operations. As of June 30, 2018, we had approximately $0.4 million accrued related to the KEIP.

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

For the quarter ended June 30, 2018, there were no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017, as supplemented by our Periodic Report on Form 10-Q for the period ended June 30, 2018.

Due to the nature of the oil and natural gas business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews of our policies and properties to identify changes in the environmental risk profile. In these reviews we evaluate whether there is a probable liability, its amount and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any remediation effort.

We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. As of June 30, 2018, we know of no significant probable or possible environmental contingent liabilities.

As of June 30, 2018, we have posted $32.0 million in various letters of credit to secure our drilling and related operations. During the second quarter, our various letters of credit were cash collateralized and the cash is shown on our Consolidated Balance Sheet as Restricted Cash.

As of June 30, 2018, we have lease commitments for various real estate leases. Rent expense is recognized on a straight-line basis and has been recorded in General and Administrative expense on our Consolidated Statements of Operations. Rent expense for the three and six months ended June 30, 2018 was approximately $0.2 million and $0.5 million, respectively, and $0.2 million and $0.5 million for the three and six months ended June 30, 2017, respectively. Lease commitments by year for each of the next five years are presented in the table below:

We have a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest in Butler County, Pennsylvania to process our produced natural gas. In the event that we do not utilize the plants to process quantities of gas sufficient to meet specified volume commitments, we may be obligated to pay approximately $8.8 million in 2018, $17.6 million in 2019, $17.6 million in 2020, $17.5 million in 2021, $17.6 million in 2022 and $68.8 million thereafter, assuming our average net revenue interest in the region of approximately 56%. Charges incurred for unutilized processing capacity with MarkWest during the three and six months ended June 30, 2018 were $0.6 million and $1.2 million, respectively and $1.7 million and $3.3 million during the three and six months ended June 30, 2017, respectively.

We have contracted with a water district in Ohio to supply bulk water in support of our Ohio drilling operations. The contract is effective from July 5, 2017 through July 4, 2022. Over the duration the contract, we are obligated to purchase 150 million gallons of water at a fixed price of $7.50 per 1,000 gallons. As of June 30, 2018, our future commitment for unpurchased volumes is approximately $0.6 million.

We have contracted drilling rig services for one rig to support our Appalachian Basin operations. During the second quarter of 2018, we terminated the contract for this rig earlier than its original term. To satisfy the early release, we incurred approximately $1.2 million in early termination fees, which were classified as Other Operating expense in our Consolidated Statement of Operations as of June 30, 2018. We also have contracted completion services in the Appalachian Basin. During the second quarter of 2018, we did not meet the contracted total stage commitment before the end of the contract. To satisfy the remaining commitment owed, we incurred approximately $0.1 million in termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations as of June 30, 2018.

During the normal course of business, we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our natural gas, NGLs and condensate. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $363.1 million through 2029.

For the three and six months ended June 30, 2018, we incurred expenses related to the transportation, processing and marketing of our natural gas, condensate and NGLs of approximately $34.1 million and $65.2 million, respectively and $26.4 million and $52.7 million for the three and six months ended June 30, 2017, respectively. Expense related to these agreements makes up a substantial portion of our Lease Operating Expense, which we expect to continue as existing agreements commence and new transportation, processing and marketing agreements are entered that will enable us to sell our product. During the three and six months ended June 30, 2018, we incurred fees related to unutilized capacity commitments of approximately $0.7 million and $1.4 million, respectively and $0.7 million and $1.4 million during the three and six months ended June 30, 2017, respectively. The unutilized commitment fees are related to undeveloped properties that we acquired during 2014. Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up to $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of WTI as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of June 30, 2018, the first seven of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI of five out of the seven below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds for the first five measurement periods. As of June 30, 2018 the calculated average spot price of WTI was above the threshold price in the agreement, we then have qualified to receive the additional proceeds for the current period. As of June 30, 2018, we have the potential to receive up to $3.6 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 9, Derivative Instruments and Fair Value Measurements, to our Consolidated Financial Statements.

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. All fees owed are due on April 1 of each year. For the three and six months ended June 30, 2018, we recorded expense of approximately $0.5 million and $1.1 million, respectively and $0.8 million and $1.6 million for the three and six months ended June 30, 2017, respectively. We record expenses related to the impact fees as Production and Lease Operating Expense. As of June 30, 2018, approximately $1.1 million was accrued for the 2018 impact fees.

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the three and six months ended June 30, 2018, we excluded stock options to purchase 69,123 shares of our common stock, due to the exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2017, we excluded stock options to purchase 112,348 shares of our common stock, due to the exercise price of all exercisable outstanding options exceeding the average market price of our common shares during the period. For the three and six months ended June 30, 2018, there were no performance-based restricted shares excluded. For the three and six months ended June 30, 2017, we excluded performance-based restricted stock of 43,124 shares and 71,715 shares, respectively, due to performance metrics that have not yet been attained (for additional information on our non-cash compensation plans, see Note 11, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the three and six month periods ended June 30, 2018 and 2017, we excluded the assumed conversion of preferred stock equating to 221,502 common shares, due to the antidilutive effect caused by the assumed conversion. The following table sets forth the computation of basic and diluted earnings per common share:

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly owned with WPX Energy Inc. (“WPX”) and Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively, “Sumitomo”), with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the sale of our interest in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania (the “Westmoreland Sale”). For additional information regarding the Westmoreland Sale, see Note 5, Oil and Gas Properties – Joint Ventures and Divestitures, to our Consolidated Financial Statements.

During the six months ended June 30, 2018, we incurred approximately $0.2 million in compression expenses that were charged to us from Williams Production Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2017, there were no receivables or payables due between RW Gathering and us.

For the three and six months ended June 30, 2018, impairment expenses incurred were approximately $4.3 million and $12.5 million, respectively, and impairment expenses incurred for the three and six months ended June 30, 2017, were approximately $3.0 million and $4.6 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment. The expense incurred during the first six months of 2018 included approximately $11.3 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Impairments of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first six months of 2018. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of each period end related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets and future development plans. Our estimates of future cash flows attributable to our oil and gas properties could decline if commodity prices decline, which may result in our incurrence of additional impairment expense. As of June 30, 2018, we continued to carry the costs of undeveloped properties of approximately $174.6 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale and for which we currently have development, trade or lease extension plans.

The expense incurred during the first six months of 2017 included approximately $3.8 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which were in Butler County, Pennsylvania and Warrior North in Ohio. Impairments of proved properties in our Butler County operations totaled approximately $0.8 million during the first six months of 2017

For the three and six months ended June 30, 2018, exploration expenses incurred were approximately $0.1 million and $0.3 million, respectively and approximately $0.1 million and $0.3 million for the three and six months ended June 30, 2017, respectively. Approximately $0.2 million of the expense incurred in 2018 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals. Approximately $0.2 million of the expense incurred in 2017 was due to geological and geophysical type expenditures and the remaining $0.1 million was due to delay rentals.

As of June 30, 2018, we had $600.3 million aggregate principal amount of outstanding Senior Notes, as shown in Note 8, Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of June 30, 2018:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures Holdings, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of June 30, 2018, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017, the condensed consolidating statements of operations for the three and six months ended June 30, 2018 and 2017, and the condensed consolidating statements of cash flows for the six months ended June 30, 2018 and 2017.

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	28,777		$	—		$	3		$	—		$	28,780
Restricted Cash		—			—			33,106			—			33,106
Accounts Receivable		26,961			—			1,627			—			28,588
Taxes Receivable		—			—			48			—			48
Short-Term Derivative Instruments		2,346			—			2,450			—			4,796
Inventory, Prepaid Expenses and Other		3,389			—			—			—			3,389
Total Current Assets		61,473			—			37,234			—			98,707
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,062,986			—			—			—			1,062,986
Unevaluated Oil and Gas Properties		174,608			—			—			—			174,608
Other Property and Equipment		20,066			—			—			—			20,066
Wells and Facilities in Progress		2,552			—			—			—			2,552
Pipelines		16,528			—			—			—			16,528
Total Property and Equipment		1,276,740			—			—			—			1,276,740
Less: Accumulated Depreciation, Depletion and Amortization		(384,556	)		—			—			—			(384,556	)
Net Property and Equipment		892,184			—			—			—			892,184
Other Assets		35			—			—			—			35
Intercompany Receivables		—			—			1,118,701			(1,118,701	)		—
Investment in Subsidiaries – Net		(2,805	)		—			(287,208	)		290,013			—
Long-Term Derivative Instruments		1,463			—			—			—			1,463
Deferred Tax Assets - Long Term		—			—			130			—			130
Total Assets	$	952,350		$	—		$	868,857		$	(828,688	)	$	992,519
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	32,679		$	—		$	50,000		$	—		$	82,679
Current Maturities of Long-Term Debt		—			—		$	261,315			—			261,315
Debtor-in Possession Term Loan Payable		—			—			35,000			—			35,000
Accrued Liabilities		18,074			—			12,862			—			30,936
Short-Term Derivative Instruments		19,095			—			—			—			19,095
Total Current Liabilities		69,848			—			359,177			—			429,025
Long-Term Derivative Instruments		12,075			—			—			—			12,075
Future Abandonment Cost		8,626			—			—			—			8,626
Liabilities Subject to Compromise		37,230			—			630,394			—			667,624
Intercompany Payables		1,114,295			4,406			—			(1,118,701	)		—
Total Liabilities		1,242,074			4,406			989,571			(1,118,701	)		1,117,350
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			11			—			11
Additional Paid-In Capital		177,143			—			654,721			(177,143	)		654,721
Accumulated Deficit		(466,867	)		(4,406	)		(775,447	)		467,156			(779,564	)
Total Stockholders’ Equity		(289,724	)		(4,406	)		(120,714	)		290,013			(124,831	)
Total Liabilities and Stockholders’ Equity	$	952,350		$	—		$	868,857		$	(828,688	)	$	992,519

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	75,155		$	—	$	—		$	—	$	75,155
Other Operating Revenue		3			—		—			—		3
TOTAL OPERATING REVENUE		75,158			—		—			—		75,158
OPERATING EXPENSES
Production and Lease Operating Expense		36,756			—		—			—		36,756
General and Administrative Expense		4,235			—		187			—		4,422
Impairment Expense		4,334			—		—			—		4,334
Exploration Expense		122			—		—			—		122
Depreciation, Depletion, Amortization and Accretion		16,953			—		—			—		16,953
Other Operating Expense		1,492			—		—			—		1,492
TOTAL OPERATING EXPENSES		63,892			—		187			—		64,079
INCOME (LOSS) FROM OPERATIONS		11,266			—		(187	)		—		11,079
OTHER INCOME (EXPENSE)
Interest Expense		(662	)		—		(13,456	)		—		(14,118	)
(Loss) Gain on Derivatives, Net		(18,413	)		—		4,085			—		(14,328	)
Other (Expense) Income		53			—		(14,005	)		—		(13,952	)
Reorganization Items, Net		(1,314	)		—		29,949			—		28,635
Loss from Equity in Consolidated Subsidiaries		—			—		(9,070	)		9,070		—
TOTAL OTHER INCOME (EXPENSE)		(20,336	)		—		(2,497	)		9,070		(13,763	)
LOSS BEFORE INCOME TAX		(9,070	)		—		(2,684	)		9,070		(2,684	)
Income tax Benefit		—			—		—			—		—
NET LOSS	$	(9,070	)	$	—	$	(2,684	)	$	9,070	$	(2,684	)
Preferred Stock Dividends		—			—		(598	)		—		(598	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(9,070	)	$	—	$	(3,282	)	$	9,070	$	(3,282	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	140,180		$	—	$	—		$	—	$	140,180
Other Operating Revenue		7			—		—			—		7
TOTAL OPERATING REVENUE		140,187			—		—			—		140,187
OPERATING EXPENSES
Production and Lease Operating Expense		70,602			—		—			—		70,602
General and Administrative Expense		9,739			—		1,207			—		10,946
Loss on Disposal of Assets		647			—		—			—		647
Impairment Expense		12,503			—		—			—		12,503
Exploration Expense		350			—		—			—		350
Depreciation, Depletion, Amortization and Accretion		32,081			—		—			—		32,081
Other Operating Expense		1,695			—		—			—		1,695
TOTAL OPERATING EXPENSES		127,617			—		1,207			—		128,824
INCOME (LOSS) FROM OPERATIONS		12,570			—		(1,207	)		—		11,363
OTHER INCOME (EXPENSE)
Interest Expense		(1,333	)		—		(35,432	)		—		(36,765	)
Loss on Derivatives, Net		(13,088	)		—		(47,666	)		—		(60,754	)
Other Expense		(951	)		—		(14,004	)		—		(14,955	)
Reorganization Items, Net		(1,313	)		—		29,948			—		28,635
(Loss) Income From Equity in Consolidated Subsidiaries		—			—		(4,115	)		4,115		—
TOTAL OTHER INCOME (EXPENSE)		(16,685	)		—		(71,269	)		4,115		(83,839	)
LOSS BEFORE INCOME TAX		(4,115	)		—		(72,476	)		4,115		(72,476	)
Income Tax Benefit		—			—		—			—		—
NET LOSS	$	(4,115	)	$	—	$	(72,476	)	$	4,115	$	(72,476	)
Preferred Stock Dividends		—			—		(1,196	)		—		(1,196	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(4,115	)	$	—	$	(73,672	)	$	4,115	$	(73,672	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net (Loss) Income	$	(4,115	)	$	—	$	(72,476	)	$	4,115			(72,476	)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion		32,081			—		—			—			32,081
Loss on Derivatives, Net		13,088			—		47,666			—			60,754
Cash Settlements of Derivatives		(6,862	)		—		—			—			(6,862	)
Equity-based Compensation Expense		(7	)		—		1,207			—			1,200
Impairment Expense		12,503			—		—			—			12,503
Non-cash Interest Expense		—			—		2,881			—			2,881
Loss on Disposal of Assets		647			—		—			—			647
Non-cash Reorganization Items, Net		—			—		(43,509	)		—			(43,509	)
Other Non-cash Expense (Income)		588			—		(22	)		—			566
Changes in operating assets and liabilities
Accounts Receivable		(342	)		—		—			—			(342	)
Taxes Receivable		—			—		2,001			—			2,001
Inventory, Prepaid Expenses and Other Assets		(2,173	)		—		2,509			—			336
Accounts Payable and Accrued Liabilities		7,778			—		33,700			—			41,478
Other Assets and Liabilities		(147	)		—		—			—			(147	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		53,039			—		(26,043	)		4,115			31,111
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		46,062			—		(41,947	)		(4,115	)		—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		16,384			—		—			—			16,384
Acquisitions of Undeveloped Acreage		(871	)		—		—			—			(871	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(100,136	)		—		—			—			(100,136	)
NET CASH USED IN INVESTING ACTIVITIES		(38,561	)		—		(41,947	)		(4,115	)		(84,623	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Line of Credit, net of Discounts		—			—		69,846			—			69,846
Proceeds from Debtor-in Possession Financing		—			—		35,000			—			35,000
Repayments of Loans and Other Long-Term Debt		(945	)		—		—			—			(945	)
Reorganization Item - Debtor-In-Possession Financing Fee		—			—		(3,750	)		—			(3,750	)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(945	)		—		101,096			—			100,151
Net Increase in Cash, Cash Equivalents and Restricted Cash		13,533			—		33,106			—			46,639
Beginning Cash, Cash Equivalents and Restricted Cash		15,244			—		3			—			15,247
Ending Cash, Cash Equivalents and Restricted Cash	$	28,777		$	—	$	33,109		$	—		$	61,886

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	15,244		$	—		$	3		$	—		$	15,247
Accounts Receivable		25,974			—			—			—			25,974
Taxes Receivable		—			—			2,049			—			2,049
Short-Term Derivative Instruments		8,008			—			—			—			8,008
Inventory, Prepaid Expenses and Other		2,106			—			2,508			—			4,614
Total Current Assets		51,332			—			4,560			—			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,086,625			—			—			—			1,086,625
Unevaluated Oil and Gas Properties		186,523			—			—			—			186,523
Other Property and Equipment		19,640			—			—			—			19,640
Wells and Facilities in Progress		38,660			—			—			—			38,660
Pipelines		16,803			—			—			—			16,803
Total Property and Equipment		1,348,251			—			—			—			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(463,899	)		—			—			—			(463,899	)
Net Property and Equipment		884,352			—			—			—			884,352
Other Assets		44			—			—			—			44
Intercompany Receivables		—			—			1,072,637			(1,072,637	)		—
Investment in Subsidiaries – Net		(2,484	)		—			(272,261	)		274,745			—
Long-Term Derivative Instruments		(2	)		—			1,721			—			1,719
Deferred Tax Assets - Long Term		—			—			130			—			130
Total Assets	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	62,354		$	—		$	—		$	—		$	62,354
Current Maturities of Long-Term Debt		1,926			—			832,399			—			834,325
Accrued Liabilities		32,214			—			13,004			—			45,218
Short-Term Derivative Instruments		14,892			—			—			—			14,892
Total Current Liabilities		111,386			—			845,403			—			956,789
Long-Term Derivative Instruments		14,249			—			—			—			14,249
Long-Term Debt		—			—			—			—			—
Other Long-Term Debt		8,156			—			—			—			8,156
Other Deposits and Liabilities		7,153			—			—			—			7,153
Future Abandonment Cost		9,352			—			—			—			9,352
Intercompany Payables		1,068,231			4,406			—			(1,072,637	)		—
Total Liabilities		1,218,527			4,406			845,403			(1,072,637	)		995,699
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			652,917			(177,144	)		652,917
Accumulated Deficit		(462,429	)		(4,406	)		(691,544	)		451,889			(706,490	)
Total Stockholders’ Equity		(285,285	)		(4,406	)		(38,616	)		274,745			(53,562	)
Total Liabilities and Stockholders’ Equity	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	47,457		$	—		$	—		$	—		$	47,457
Other Operating Expense		5			—			—			—			5
TOTAL OPERATING REVENUE		47,462			—			—			—			47,462
OPERATING EXPENSES
Production and Lease Operating Expense		29,374			—			—			—			29,374
General and Administrative Expense		3,771			—			523			—			4,294
Gain on Disposal of Assets		(124	)		—			—			—			(124	)
Impairment Expense		3,032			—			—			—			3,032
Exploration Expense		99			—			—			—			99
Depreciation, Depletion, Amortization and Accretion		15,501			—			—			—			15,501
Other Operating (Income) Expense		(99	)		1			—			—			(98	)
TOTAL OPERATING EXPENSES		51,554			1			523			—			52,078
LOSS FROM OPERATIONS		(4,092	)		(1	)		(523	)		—			(4,616	)
OTHER INCOME (EXPENSE)														—
Interest Expense		(442	)		—			(11,680	)		—			(12,122	)
(Loss) Gain on Derivatives, Net		10,861			—			(475	)		—			10,386
Other Income		20			—			—						20
Loss on Extinguishments of Debt		—			—			(3,271	)					(3,271	)
Income (Loss) From Equity in Consolidated Subsidiaries		(1	)		—			6,346			(6,345	)		—
TOTAL OTHER INCOME (EXPENSE)		10,438			—			(9,080	)		(6,345	)		(4,987	)
INCOME (LOSS) BEFORE INCOME TAX		6,346			(1	)		(9,603	)		(6,345	)		(9,603	)
Income Tax Benefit		—			—			—			—			—
NET INCOME (LOSS)		6,346			(1	)		(9,603	)		(6,345	)		(9,603	)
Preferred Stock Dividends		—			—			(598	)		—			(598	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	6,346		$	(1	)	$	(10,201	)	$	(6,345	)	$	(10,201	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	99,522		$	—		$	—		$	—		$	99,522
Other Revenue		11			—			—			—			11
TOTAL OPERATING REVENUE		99,533			—			—			—			99,533
OPERATING EXPENSES
Production and Lease Operating Expense		58,308			—			—			—			58,308
General and Administrative Expense		8,232			—			596			—			8,828
Gain on Disposal of Assets		(1,959	)		—			—			—			(1,959	)
Impairment Expense		4,577			—			—			—			4,577
Exploration Expense		319			—			—			—			319
Depreciation, Depletion, Amortization and Accretion		30,969			—			—			—			30,969
Other Operating (Income) Expense		(119	)		1			—			—			(118	)
TOTAL OPERATING EXPENSES		100,327			1			596			—			100,924
LOSS FROM OPERATIONS		(794	)		(1	)		(596	)		—			(1,391	)
OTHER INCOME (EXPENSE)
Interest Expense		(809	)		—			(20,457	)		—			(21,266	)
(Loss) Gain on Derivatives, Net		20,659			—			(1,893	)		—			18,766
Other Expense		(7	)		—			—			—			(7	)
Loss on Extinguishments of Debt		—			—			(3,022	)		—			(3,022	)
Income (Loss) From Equity in Consolidated Subsidiaries		(1	)		—			19,048			(19,047	)		—
TOTAL OTHER INCOME (EXPENSE)		19,842			—			(6,324	)		(19,047	)		(5,529	)
INCOME (LOSS) BEFORE INCOME TAX		19,048			(1	)		(6,920	)		(19,047	)		(6,920	)
Income Tax Benefit		—			—			—			—			—
NET INCOME (LOSS)		19,048			(1	)		(6,920	)		(19,047	)		(6,920	)
Preferred Stock Dividends		—			—			(1,196	)		—			(1,196	)
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	19,048		$	(1	)	$	(8,116	)	$	(19,047	)	$	(8,116	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	19,048		$	(1	)	$	(6,920	)	$	(19,047	)	$	(6,920	)
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation, Depletion, Amortization and Accretion		30,969			—			—			—			30,969
(Gain) Loss on Derivatives, Net		(20,659	)		—			1,893			—			(18,766	)
Cash Settlements of Derivatives		(5,525	)		—			—			—			(5,525	)
Equity-based Compensation Expense		—			—			571			—			571
Non-cash Exploration Expense		13			—			—			—			13
Gain on Disposal of Assets		(1,959	)		—			—			—			(1,959	)
Loss on Extinguishments of Debt		—			—			3,022			—			3,022
Non-cash Interest Expense		—			—			12,431			—			12,431
Impairment Expense		4,577			—			—			—			4,577
Other Non-Cash Expense		41			—			—			—			41
Changes in operating assets and liabilities
Accounts Receivable		7,232			—			(3	)		—			7,229
Taxes Receivable		—						163
Inventory, Prepaid Expenses and Other Assets		638			—			(586	)		—			52
Accounts Payable and Accrued Liabilities		(1,484	)		—			—			—			(1,484	)
Other Assets and Liabilities		(1,104	)		—			—			—			(1,104	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		31,787			(1	)		10,571			(19,047	)		23,310
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany loans to subsidiaries		4,063			1			(23,111	)		19,047			—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		24,513			—			—			—			24,513
Acquisitions of Undeveloped Acreage		(1,783	)		—			—			—			(1,783	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(54,004	)		—			—			—			(54,004	)
NET CASH USED IN INVESTING ACTIVITIES		(27,211	)		1			(23,111	)		19,047			(31,274	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit, net of Discounts		—			—			171,000			—			171,000
Repayments of Long Term Debt and Lines of Credit		—			—			(145,170	)		—			(145,170	)
Repayments of Loans and Other Long-Term Debt		(319	)		—			—			—			(319	)
Debt Issuance Costs		—						(7,791	)					(7,791	)
Payment of Preferred Dividends in arrears		—			—			(598	)		—			(598	)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		(319	)		—			17,441			—			17,122
NET INCREASE IN CASH		4,257			—			4,901			—			9,158
CASH – BEGINNING		3,694			—			3			—			3,697
CASH - ENDING	$	7,951		$	—		$	4,904		$	—		$	12,855

On July 11, 2018, the Bankruptcy Court issued a Final Order approving the motion (i) Authorizing The Debtors To Obtain Senior Secured, Superpriority, Post-Petition Financing, (II) Authorizing Use of Cash Collateral, (III) Granting Priming Liens, Priority Liens and Super-Priority Claims and (IV) Granting Adequate Protection To Prepetition Secured Parties. The approved motion authorized the Rex Debtors to obtain from our pre-petition First Lien lenders a post-petition delayed draw term loan facility in the aggregate principal amount of up to $411,315,322, consisting of the prior Term Loan balance of $261,315,322, the Make Whole Amount of $50,000,000, and $100,000,000 of funding available to finance post-petition operations throughout the Chapter 11 process (the “Additional Borrowing Capacity”). As of June 30, 2018, we had drawn $35,000,000 of the Additional Borrowing Capacity.

The approval of the roll-up of the First Lien prepetition term debt and credit agreement Make Whole Amount into the final approved DIP Facility secures all claims held by our First Lien lenders with first-position priority claims status.

The following is management’s discussion and analysis of certain significant factors that have affected aspects of our financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements for the year ended December 31, 2017 included in our Annual Report on Form 10-K and the unaudited financial statements included elsewhere herein.

We use a variety of financial and operational measurements at interim periods to analyze our performance. These measurements include an analysis of production and sales revenue for the period; EBITDAX, a non-GAAP financial measurement; lease operating expenses per Mcf equivalent (“LOE per Mcfe”); and general and administrative (“G&A”) expenses per Mcfe.

We are an independent natural gas, NGL and condensate company operating in the Appalachian Basin, where we are focused on our Marcellus Shale, Utica Shale and Upper Devonian Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties. We are headquartered in State College, Pennsylvania, with a regional office in Cranberry, Pennsylvania.

We believe the outlook for our business is favorable despite the continued uncertainty of natural gas and oil prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve.

However, a prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our natural gas and oil properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “Commodity Prices,” “Impairment Expense,” “Capital Resources and Liquidity,” and “Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 16, “Impairment Expense”, to our Consolidated Financial Statements.

On March 13, 2018, we, entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which we agreed to sell to XPR certain of our non-operated oil and gas interests in 61 wells located in Westmoreland and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to the Company. In a related transaction, we entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which we agreed to sell to COG2 our 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

On May 18, 2018 (the “Petition Date”), we and certain of our direct subsidiaries (collectively the “Rex Debtors”) filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Western District of Pennsylvania (the “Bankruptcy Court”). During the pendency of the Chapter 11 proceedings, the Rex Debtors will operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Rex Debtors’ Chapter 11 cases are being administered jointly under the caption In re R.E. Gas Development, LLC, et al., Case No. 18-22032.

The Rex Debtors are operating their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court has granted certain relief requested by the Debtors, allowing us to use our cash to fund the Chapter 11 proceedings, pursuant to an agreement with the first lien lenders, and giving us the authority to, among other things, continue to pay employee wages and benefits without interruption, to utilize our current cash management system and to make royalty payments. During the pendency of the Chapter 11 proceedings, all transactions outside the ordinary course of our business require prior approval of the Bankruptcy Court. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms.

In order to exit Chapter 11 successfully, the Rex Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization (a “Plan”) that satisfies the requirements of the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a proposed Plan (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the resolution of the outstanding claims against and interests in the Debtors pursuant to the Bankruptcy Code. On July 25, 2018, the Debtors filed with the Bankruptcy Court a related proposed disclosure statement (as may be amended, modified or supplemented from time to time, the “Proposed Disclosure Statement”). In addition to being voted on by holders of impaired claims and equity interests, the Proposed Plan must satisfy certain requirements of the Bankruptcy Code and must be approved, or confirmed, by the Bankruptcy Court in order to become effective. If accepted by holders of impaired claims and equity interests, the Proposed Plan would, among other things, resolve the Debtors’ prepetition obligations, and set forth the revised capital structure of the newly reorganized entity, unless all or substantially all of the Debtors' assets are sold during the Chapter 11 proceedings. The Debtors will seek approval of the Proposed Disclosure Statement on August 23, 2018, and, if obtained, will solicit votes on the Proposed Plan.

On June 1, 2018, the Rex Debtors filed with the Bankruptcy Court a Motion For Orders Pursuant To Section 363 of the Bankruptcy Code: (I)(A) Approving Bidding Procedures For The Sale Of The Debtors’ Assets, (B) Scheduling An Auction And Approving The Form And Manner Of Notice Thereof, (C) Approving Assumption And Assignment Procedures and (D) Scheduling A Sale Hearing And Approving The Form And Manner Of Notice Thereof; (II)(A) Approving The Sale Of The Debtors’ Assets Free And Clear Of Liens, Claims, Interests And Encumbrances and (B) Approving The Assumption And Assignment Of Executory Contracts And Unexpired Leases; and (III) Granting Related Relief. On June 29 2018, the Bankruptcy Court entered an order approving the bidding procedures and scheduling the auction.

The Company has been in discussions with various third parties who may be interested in purchasing some or all of the assets of the Rex Debtors through the bankruptcy process, either through a sale pursuant to Section 363 of Chapter 11 of the Bankruptcy Code or in connection with the Proposed Plan. At this time, it is not possible to predict accurately the effect of the Chapter 11 reorganization process on our business, creditors or stockholders, when the Rex Debtors may emerge from Chapter 11 or what the disposition will be of any claims against the Rex Debtors. Our future results depend on the timely and successful confirmation and implementation of the Proposed Plan.

Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Rex Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Rex Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Creditors are stayed from taking any actions against the Rex Debtors as a result of defaults on the Rex Debtors’ debt obligations (which defaults were triggered prior to or by the filing of Bankruptcy Petitions), subject to certain limited exceptions permitted by the Bankruptcy Code. We did not record interest expense on our 1%/8% senior secured second lien notes (“Second Lien Notes”) or our unsecured 6.25% Senior Notes due 2022 and unsecured 8.875% Senior Notes due 2020 (the “Unsecured Notes”) for the period from May 18, 2018, through June 30, 2018. For that period, contractual interest on the Second Lien Notes and the Unsecured Notes was approximately $5.7 million.

The significant risks and uncertainties related to our covenant violations, liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern. The consolidated financia l statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department (the “Staff”) of The Nasdaq Stock Market LLC (“Nasdaq”) indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unlesswe requested an appeal before the Nasdaq Hearings Panel (the “Panel”). We did not appeal this determination. Nasdaq filed a Form 25-NSE on April 19, 2018. Following the delisting of our common stock from Nasdaq, our common stock has been quoted on the OTC Markets Group’s Pink marketplace.

For the three and six months ended June 30, 2018, we produced 21,987 MMcfe and 41,859 MMcfe, respectively. Overall, our production for the three and six months ended June 30, 2018 averaged 242 MMcfe per day and 231 MMcfe per day, respectively. As of June 30, 2018, we had no wells drilled that were awaiting completion. We had no wells resting or awaiting pipeline connection as of June 30, 2018. Our drilling and completion activity for the period indicated is set forth in the table below.

Three Months Ended June 30, 2018

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

1.0

0.5

7.0

4.5

14.0

9.5

Three Months Ended June 30, 2017

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

6.0

4.8

6.0

3.1

4.0

1.4

Six Months Ended June 30, 2018

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

7.0

4.5

18.0

13.5

18.0

13.5

Six Months Ended June 30, 2017

Wells Drilled

Wells Completed

Wells Placed In Service

Gross

Net

Gross

Net

Gross

Net

14.0

8.6

10.0

4.5

4.0

1.4

Our development program for 2018 has been substantially completed. We are not anticipating any changes to this program as a result of the pending Chapter 11 bankruptcy.

Our development plans, which are substantially complete for 2018, are sensitive to current and projected commodity prices which have been and are expected to continue to be volatile. Our realized price, before derivative settlements, for natural gas during the three and six months ended June 30, 2018 averaged approximately $2.48 per Mcf and $2.58 Mcf, respectively, as compared to $2.94 Mcf and $3.05 Mcf during the three and six months ended June 30, 2017, respectively. Our realized price, before derivative settlements, for condensate during the three and six months ended June 30, 2018 averaged approximately $62.46 per barrel and $60.58 per barrel, respectively, as compared to $42.35 and $44.25 per barrel during the three and six months ended June 30, 2017, respectively. Our realized price, before derivative settlements, for C3+ NGLs during the three and six months ended June 30, 2018 averaged approximately $37.96 per barrel and $37.72 per barrel, as compared to $23.03 per barrel and $26.86 per barrel during the three and six months ended June 30, 2017, respectively. Our realized price, before derivative settlements, for ethane during the three and six months ended June 30, 2018 averaged approximately $11.15 per barrel and $10.65 per barrel, as compared to $9.96 per barrel and $9.74 per barrel during the three and six months ended June 30, 2017, respectively.

For the three and six months ended June 30, 2018, we recorded impairment expense of approximately $4.3 million and $12.5 million. Decreases in commodity prices will decrease our natural gas, NGL and condensate revenues and could reduce the amount of natural gas, NGL and condensate reserves that we can economically produce. A prolonged period of depressed commodity prices or further declines in projected future commodity prices could require additional write-downs of the carrying values of our properties.

Because we follow the successful efforts method of accounting, our impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain. In an effort to quantify the impact of continued low commodity pricing levels or further declines in future prices, we offer the following: as of June 30, 2018, approximately $564.8 million, or 80.8%, of our evaluated oil and natural gas properties were located in our Butler Marcellus operating area. Based on estimates of future cash flows, substantial further decreases in commodity prices combined with a lack of access to capital or a detrimental change to costs or operating efficiencies would need to occur in order for us to experience a write-down. Our remaining evaluated properties outside of the Butler Marcellus operating area are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties totaled approximately $134.5 million as of June 30, 2018.

During the first six months of 2017, we entered into privately negotiated debt-to-equity exchanges with certain holders of our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and together with the 2020 Notes, the “Existing Notes”) in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $0.9 million of our Existing Notes, in exchange for the issuance of 83,626 shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain of approximately $0.4 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statement of Operations for the six months ended June 30, 2017.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised its option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of June 30, 2018. BSP has paid for its interest in elected wells as of December 31, 2017, and no additional elections have occurred during the quarter ended June 30, 2018. The remainder of the proceeds may be received if BSP makes additional elections as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of June 30, 2018, all 45 committed wells were in line and producing.

The following table sets forth summary information regarding natural gas, NGL and condensate production and product prices for the three and six months ended June 30, 2018 and 2017:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
Production:
Natural Gas (Mcf)		11,996,504		9,889,888		23,011,737		19,801,630
Condensate (Bbls)		210,656		70,687		326,539		144,927
C3+ NGLs (Bbls)		599,383		439,441		1,146,891		861,146
Ethane (Bbls)		855,119		526,893		1,667,813		979,580
Total (Mcfe)(a)		21,987,452		16,112,014		41,859,195		31,715,548
Average daily production:
Natural Gas (Mcf)		131,830		108,680		127,137		109,401
Condensate (Bbls)		2,315		777		1,804		801
C3+ NGLs (Bbls)		6,587		4,829		6,336		4,758
Ethane (Bbls)		9,397		5,790		9,214		5,412
Total (Mcfe)(a)		241,620		177,055		231,266		175,224
Average sales price(b):
Natural Gas (per Mcf)	$	2.48	$	2.94	$	2.58	$	3.05
Condensate (per Bbl)	$	62.46	$	42.35	$	60.58	$	44.25
C3+ NGLs (per Bbl)	$	37.96	$	23.03	$	37.72	$	26.86
Ethane (per Bbl)	$	11.15	$	9.96	$	10.65	$	9.74
Total (per Mcfe)(a)	$	3.42	$	2.95	$	3.35	$	3.14
Average NYMEX prices(c):
Oil (per Bbl)	$	67.99	$	48.28	$	65.43	$	50.10
Natural Gas (per Mcf)	$	2.82	$	3.05	$	2.91	$	3.02

The following table sets forth summary information regarding natural gas, NGL and condensate revenues, production volumes, average product prices and average production costs for the three and six months ended June 30, 2018 and 2017:

Operating revenue for the three and six months ended June 30, 2018 increased 58.4% and 40.9% when compared to the same periods in 2017, respectively. The increase in operating revenue for the three and six months ended June 30, 2018 can be primarily attributed to higher production volumes and condensate and NGL prices. Our production increased to 21,897 MMcfe for the three month period ended June 30, 2018 from 16,112 MMcfe for the three month period ended June 30, 2017, or approximately 36.5%. For the six months ended June 30, 2018, our production increased 32.0% to 41,859 MMcfe from the six months ended June 30, 2017. For the three month period ended June 30, 2018 our realized sales price for natural gas decreased to $2.48 per Mcf from $2.94 per Mcf, condensate increased to $62.46 per barrel from $42.35 per barrel, C3+ NGLs increased to $37.96 per barrel from $23.03 per barrel, and ethane increased to $11.15 per barrel from $9.96 per barrel, respectively, when compared to the same period in 2017. For the six month period ended June 30, 2018 our realized sales price for natural gas decreased to $2.58 per Mcf from $3.05 per Mcf, condensate increased to $60.58 per barrel from $44.25 per barrel, C3+ NGLs increased to $37.72 per barrel from $26.86 per barrel, and ethane increased to $10.65 per barrel from $9.74 per barrel, respectively, when compared to the same period in 2017.

Operating expenses increased $12.0 million and $27.9 million for the three and six months ended June 30, 2018, as compared to the same periods in 2017. Operating expenses are primarily composed of: Production and Lease Operating Expenses, G&A Expenses, Other Operating Expense, Exploration Expenses, Impairment Expense and Depreciation, Depletion, Amortization and Accretion (“DD&A”) Expenses. The increase in operating expenses were largely attributable to an increase in production and lease operating expense due to higher production volume, impairment charges, a loss on the disposal of an asset and higher G&A expenses due to employee costs. The increase of many of these operating expenses is consistent with our overall drilling activity, which is in accordance with our capital plan. The increase in impairment was largely due to undeveloped leases that expired or are expected to expire without being developed.

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the three-month periods ended June 30, 2018 and 2017 is summarized in the following table:

	For the Three Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2018			2017			Change			%
Gas sales revenue	$	29,705		$	29,097		$	608			2.1	%
Gas derivatives realized(a)	$	3,153		$	(1,594	)	$	4,747			(297.8	)%
Total gas revenue and derivatives realized	$	32,858		$	27,503		$	5,355			19.5	%
Condensate sales revenue	$	13,157		$	2,993		$	10,164			339.6	%
Oil and condensate derivatives realized(a)	$	(2,533	)	$	141		$	(2,674	)		(1,896.5	)%
Total condensate revenue and derivatives realized	$	10,624		$	3,134		$	7,490			239.0	%
C3+ NGL revenue	$	22,754		$	10,119		$	12,635			124.9	%
C3+ NGL derivatives realized(a)	$	(6,137	)	$	(616	)	$	(5,521	)		896.3	%
Total C3+ NGL revenue	$	16,617		$	9,503		$	7,114			74.9	%
Ethane revenue	$	9,539		$	5,247		$	4,292			81.8	%
Ethane derivatives realized(a)	$	664		$	(12	)	$	676			(5,633.3	)%
Total Ethane revenue	$	10,203		$	5,235		$	4,968			94.9	%
Consolidated sales	$	75,155		$	47,456		$	27,699			58.4	%
Consolidated derivatives realized(a)	$	(4,853	)	$	(2,081	)	$	(2,772	)		133.2	%
Total NGL, condensate and gas revenue and derivatives realized	$	70,302		$	45,375		$	24,927			54.9	%
Total Mcfe Production		21,987,452			16,112,014			5,875,438			36.5	%
Average Realized Price per Mcfe	$	3.20		$	2.82		$	0.38			13.5	%

Average realized price received for natural gas, NGLs and condensate during the second quarter of 2018, after the effect of derivative activities, was $3.20 per Mcfe, an increase of 13.5%, or $0.38 per Mcfe, from the same period in 2017. The average price for natural gas, after the effect of derivative activities, decreased 1.5%, or $0.04 per Mcf, to $2.74 per Mcf. The average price for condensate, after the effect of derivative activities, increased 13.8%, or $6.11 per barrel, to $50.44 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 28.2%, or $6.11 per barrel, to $27.73 per barrel. The average price for ethane, after the effect of derivative activities, increased 20.2%, or $2.01 per barrel, to $11.94 per barrel. Our derivative activities effectively decreased net realized prices by $0.22 per Mcfe and $0.13 per Mcfe in the second quarter of 2018 and 2017, respectively.

Our realized sales price for natural gas was lower than the average Henry Hub NYMEX pricing by approximately $0.34 per Mcf during the second quarter of 2018, primarily due to basis differentials in the northeastern United States, which were partially offset by sales to the Gulf Coast, which receive Henry Hub NYMEX pricing. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast, including transportation of 130,000 Mcf per day to the Gulf Coast.

Production volumes in the second quarter of 2018 increased 36.5%, or 5,875.4 MMcfe, from the second quarter of 2017 primarily the success of our Marcellus and Utica Shale horizontal drilling activities and the sale of our Warrior South assets during first quarter of 2017, which decreased volumes during the prior year. Natural gas production increased approximately 21.3%, condensate production increased approximately 198.0%, C3+ NGL production increased approximately 36.4% and ethane production increased approximately 62.3%.

Overall, our production for the second quarter of 2018 averaged 241,620 Mcfe per day, of which 54.6% was attributable to natural gas, 5.7% to condensate, 16.4% to C3+ NGLs and 23.3% to ethane production.

Statements of Operations for the three months ended June 30, 2018 and 2017 are as follows:

	For the Three Months Ended June 30,
($ in Thousands)	2018			2017			Change			%
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	75,155		$	47,457		$	27,698			58.4	%
Other Operating Revenue		3			5			(2	)		(40.0	)%
TOTAL OPERATING REVENUE		75,158			47,462			27,696			58.4	%
OPERATING EXPENSES
Production and Lease Operating Expense		36,756			29,374			7,382			25.1	%
General and Administrative Expense		4,422			4,294			128			3.0	%
Gain on Disposal of Assets		—			(124	)		124			(100.0	)%
Impairment Expense		4,334			3,032			1,302			42.9	%
Exploration Expense		122			99			23			23.2	%
Depreciation, Depletion, Amortization and Accretion		16,953			15,501			1,452			9.4	%
Other Operating (Income) Expense		1,492			(98	)		1,590			(1,622.4	)%
TOTAL OPERATING EXPENSES		64,079			52,078			12,001			23.0	%
INCOME (LOSS) FROM OPERATIONS		11,079			(4,616	)		15,695			(340.0	)%
OTHER INCOME (EXPENSE)
Interest Expense		(14,118	)		(12,122	)		(1,996	)		16.5	%
(Loss) Gain on Derivatives, Net		(14,328	)		10,386			(24,714	)		(238.0	)%
Other (Expense) Income		(13,952	)		20			(13,972	)		(69,860.0	)%
Loss on Extinguishments of Debt		—			(3,271	)		3,271			(100.0	)%
Reorganization Items, Net		28,635			—			28,635			100.0	%
TOTAL OTHER EXPENSE		(13,763	)		(4,987	)		(8,776	)		176.0	%
LOSS BEFORE INCOME TAX		(2,684	)		(9,603	)		6,919			(72.1	)%
Income Tax Benefit		—			—			—		N/A
NET LOSS		(2,684	)		(9,603	)		6,919			(72.1	)%

Production and Lease Operating Expense increased approximately $7.4 million, or 25.1%, in the second quarter of 2018 from the same period in 2017. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells, firm capacity expense related to additional avenues in delivering our products and variable costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 88.8% of our total Production and Lease Operating Expense in the second quarter of 2018, as compared to 89.9% from the same period in 2017. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs were $1.66 and $1.82 per Mcfe for the three months ended June 30, 2018 and 2017, respectively. The decrease on a per unit basis is due to flowing higher volumes, which has limited our unutilized reservation fees

G&A Expense for the second quarter of 2018 increased approximately $0.1 million, or 3.0%, to $4.4 million from the same period in 2017. The increase was mostly due to employee costs. Partially offsetting these expenses was a decrease in legal fees.

Impairment Expense for the second quarter of 2018 was approximately $4.3 million. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. The expense incurred during the second quarter of 2018 included approximately $4.3 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of June 30, 2018, which indicated that the full carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the second quarter of 2018 was approximately $0.1 million, which remained flat from the prior year. The expense incurred in 2018 was mostly due to geological and geophysical type expenditures and delay rentals, which is the same as the second quarter of 2017.

DD&A Expense for the second quarter of 2018 increased approximately $1.4 million, or 9.4%, from $15.5 million for the same period in 2017. Contributing to the increase in DD&A expense was due to depletion expense during the second quarter of 2018.

Other Operating Expense for the second quarter of 2018 increased approximately $1.6 million as compared to the same period in 2017. The expense in 2018 was primarily related to a termination fees, firm capacity commitments and inventory adjustments.

Interest Expense for the second quarter of 2018 was approximately $14.1 million as compared to $12.1 million for the same period in 2017. The increase in interest expense is due to interest charges incurred on the Debtor-In-Possession Term Loan and fees charged on available but undrawn borrowing base of the Debtor-In-Possession Term Loan established in May 2018, interest on the Term Loan, an increase in interest on the Senior Notes, due to a change in the rate from 1% to 8% and the write-off of deferred financing fees and OID related to our term loan and Senior Notes. We discuss our Debtor-In-Possession Term Loan, Term Loan and Senior Notes in Note 8, Debt, to our Consolidated Financial Statements.

(Loss) Gain on Derivatives, net included a loss of approximately $14.3 million for the second quarter of 2018 as compared to a gain of $10.4 million for the same period in 2017. The loss recorded for the second quarter of 2018 included cash payments for commodity derivatives of $4.9 million while the gain incurred in the second quarter of 2017 included cash receipts of approximately $2.1 million for commodity derivatives. Changes related to our commodity derivatives were attributable to the volatility of natural gas, NGL and oil commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher natural gas, NGL and oil prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of gas, NGL and oil production volumes given the highly volatile gas, NGL and oil commodities market.

We believe natural gas, NGL and oil prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2018 and 2019, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Other (Expense) Income for the second quarter of 2018 includes approximately $13.9 million of professional and consulting fees related to restructuring and refinancing efforts incurred prior to our filing of the Bankruptcy Petition on May 18, 2018.

Loss on Extinguishments of Debt for the second quarter of 2018 was zero. Loss on extinguishments of debt for the second quarter of 2017 totaled approximately $3.3 million, resulting from the write-off of approximately $3.5 million of unamortized debt issuance costs related to the Senior Credit Facility retired in April 2017, offset by approximately $0.2 million in gains from debt to equity exchanges completed in the second quarter of 2017. We discuss the debt to equity exchanges in Note 8, Debt, to our Consolidated Financial Statements.

Reorganization Items, Net for the second quarter of 2018 includes reorganization items as defined in ASC 852, Reorganizations. The reorganization items include both items of income and expense, netting to a net Other Income of approximately $28.6 million for the three months ending June 30, 2018. See discussion of Reorganization Items, Net, in Note 2 to our consolidated financial statements for additional details of the reorganization items.

Income Tax Expense for continuing operations for the second quarter of 2018 and 2017 was zero, due to the full valuation allowances we maintain against our net deferred tax assets.

Net Income (Loss) Attributable to Rex Energy for the second quarter of 2018 was a loss of approximately $2.7 million, as compared to a loss of $9.6 million for the same period in 2017 as a result of factors discussed above.

Gas, condensate and NGL revenue, including the effects of cash settled derivatives, for the six-month periods ended June 30, 2018 and 2017 is summarized in the following table:

	For the Six Months Ended June 30,
($ in Thousands, except total Mcfe production and price per Mcfe)	2018			2017			Change			%
Gas sales revenue	$	59,387		$	60,442		$	(1,055	)		(1.7	)%
Gas derivatives realized(a)	$	3,883		$	(2,766	)	$	6,649			(240.4	)%
Total gas revenue and derivatives realized	$	63,270		$	57,676		$	5,594			9.7	%
Condensate sales revenue	$	19,782		$	6,414		$	13,368			208.4	%
Oil and condensate derivatives realized(a)	$	(2,996	)	$	146		$	(3,142	)		(2,152.1	)%
Total condensate revenue and derivatives realized	$	16,786		$	6,560		$	10,226			155.9	%
C3+ NGL revenue	$	43,256		$	23,127		$	20,129			87.0	%
C3+ NGL derivatives realized(a)	$	(9,071	)	$	(3,001	)	$	(6,070	)		202.3	%
Total C3+ NGL revenue	$	34,185		$	20,126		$	14,059			69.9	%
Ethane revenue	$	17,755		$	9,540		$	8,215			86.1	%
Ethane derivatives realized(a)	$	1,322		$	96		$	1,226			1,277.1	%
Total Ethane revenue	$	19,077		$	9,636		$	9,441			98.0	%
Consolidated sales	$	140,180		$	99,523		$	40,657			40.9	%
Consolidated derivatives realized(a)	$	(6,862	)	$	(5,525	)	$	(1,337	)		24.2	%
Total NGL, condensate and gas revenue and derivatives realized	$	133,318		$	93,998		$	39,320			41.8	%
Total Mcfe Production		41,859,195			31,715,548			10,143,647			32.0	%
Average Realized Price per Mcfe	$	3.18		$	2.96		$	0.22			7.5	%

Average realized price received for natural gas, NGLs and condensate during the first six months of 2018, after the effect of derivative activities, was $3.19 per Mcfe, an increase of 7.6%, or $0.22 per Mcfe, from the same period in 2017. The average price for natural gas, after the effect of derivative activities, decreased 5.5%, or $0.16 per Mcf, to $2.75 per Mcf. The average price for condensate, after the effect of derivative activities, increased 13.5%, or $6.13 per barrel, to $51.40 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 27.6%, or $6.44 per barrel, to $29.81 per barrel. The average price for ethane, after the effect of derivative activities, increased 16.3%, or $1.60 per barrel, to $11.44 per barrel. Our derivative activities effectively decreased net realized prices by $0.16 per Mcfe and $0.17 per Mcfe during the first six months of 2018 and 2017, respectively.

Our realized sales price for natural gas was lower than the average Henry Hub NYMEX pricing by approximately $0.33 per Mcf during the first six months of 2018, primarily due to basis differentials in the northeastern United States, which were partially offset by sales to the Gulf Coast, which receive Henry Hub NYMEX pricing. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast, including transportation of 130,000 Mcf per day to the Gulf Coast.

Production volumes in the first six months of 2018 increased 31.7%, or 10,047.1 MMcfe, from the first six months of 2017 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities and the sale of our Warrior South assets during first quarter of 2017, which decreased volumes during the prior year. Natural gas production increased approximately 15.7%, condensate production increased approximately 125.3%, C3+ NGL production increased approximately 33.2% and ethane production increased approximately 70.3%.

Overall, our production for the first six months of 2018 averaged 230,733 Mcfe per day, of which 54.9% was attributable to natural gas, 4.7% to condensate, 16.5% to C3+ NGLs and 24.0% to ethane production.

Statements of Operations for the six months ended June 30, 2018 and 2017 are as follows:

	For the Six Months Ended June 30,
($ in Thousands)	2018			2017			Change			%
OPERATING REVENUE
Natural Gas, Condensate and NGL Sales	$	140,180		$	99,522		$	40,658			40.9	%
Other Operating Revenue		7			11			(4	)		(36.4	)%
TOTAL OPERATING REVENUE		140,187			99,533			40,654			40.8	%
OPERATING EXPENSES
Production and Lease Operating Expense		70,602			58,308			12,294			21.1	%
General and Administrative Expense		10,946			8,828			2,118			24.0	%
Loss (Gain) on Disposal of Assets		647			(1,959	)		2,606			(133.0	)%
Impairment Expense		12,503			4,577			7,926			173.2	%
Exploration Expense		350			319			31			9.7	%
Depreciation, Depletion, Amortization and Accretion		32,081			30,969			1,112			3.6	%
Other Operating (Income) Expense		1,695			(118	)		1,813			(1,536.4	)%
TOTAL OPERATING EXPENSES		128,824			100,924			27,900			27.6	%
INCOME (LOSS) FROM OPERATIONS		11,363			(1,391	)		12,754			(916.9	)%
OTHER INCOME (EXPENSE)
Interest Expense		(36,765	)		(21,266	)		(15,499	)		72.9	%
Gain (Loss) on Derivatives, Net		(60,754	)		18,766			(79,520	)		(423.7	)%
Other Expense		(14,955	)		(7	)		(14,948	)		213,542.9	%
Gain on Extinguishments of Debt		—			(3,022	)		3,022			(100.0	)%
Reorganization Items, Net		28,635			—			28,635			(—	)%
TOTAL OTHER EXPENSE		(83,839	)		(5,529	)		(78,310	)		1,416.4	%
LOSS BEFORE INCOME TAX		(72,476	)		(6,920	)		(65,556	)		947.3	%
Income Tax Benefit		—			—			—			(—	)%
NET LOSS		(72,476	)		(6,920	)		(65,556	)		947.3	%

Production and Lease Operating Expense increased approximately $12.3 million, or 21.1%, during the first six months of 2018 as compared to the same period in 2017. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells, firm capacity expense related to additional avenues in delivering our products and variable costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 88.6% of our total Production and Lease Operating Expense during the first six months of 2018, as compared to 90.7% from the same period in 2017. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs were $1.68 and $1.84 per Mcfe for the six months ended June 30, 2018 and 2017, respectively. The decrease on a per unit basis is due to flowing higher volumes, which has limited our unutilized reservation fees

G&A Expense for the first six months of 2018 increased approximately $2.1 million, or 24.0%, to $10.9 million as compared to the same period in 2017. The increase was mostly due to employee costs and expense associated with the vesting of our restricted stock, which was approximately $0.9 million. Partially offsetting these expenses was a decrease in legal and consulting fees.

Impairment Expense for the first six months of 2018 was approximately $12.5 million. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. The expense incurred during the first six months of 2018 included approximately $11.3 million of undeveloped leases that expired or are expected to expire without being developed, the majority of which are in Butler County, Pennsylvania, and Warrior North in Ohio. Based on the current commodity price environment, we do not expect to develop these properties prior to expiration of the associated leases. Impairment of proved properties in our Westmoreland County operations totaled approximately $1.2 million during the first six months of 2018. The impairments were identified through an analysis of market conditions and future development plans related to these properties that were in existence as of June 30, 2018, which indicated that the full carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. Any amount of future impairments are difficult to predict, however, if commodity prices decline, downward revisions of proved reserves may be significant and could result in additional impairment expense.

Exploration Expense for the first six months of 2018 was approximately $0.3 million, which remained flat from the prior year. The expense incurred in 2018 was mostly due to geological and geophysical type expenditures and delay rentals, which is the same as the six months of 2017.

DD&A Expense for the first six months of 2018 increased approximately $1.1 million, or 3.6%, from $31.0 million for the same period in 2017. Contributing to the increase in DD&A expense was depletion of assets during the first six months of 2018.

Other Operating Expense for the first six months of 2018 increased approximately $1.8 million as compared to the same period in 2017. The expense in 2018 was primarily related to termination fees, firm capacity commitments and inventory adjustments.

Interest Expense for the first six months of 2018 was approximately $36.8 million as compared to $21.3 million for the same period in 2017. The increase in interest expense is primarily due to interest charges and fees incurred on the Debtor-In-Possession Term Loan established in May 2018, interests incurred on the Term Loan and fees charged on available but undrawn borrowing base of the Delayed Draw Term Loan established in April 2017, an increase in interest on the Senior Notes, due to a change in the rate from 1% to 8% and the write-off of deferred financing fees and OID related to our term loan. We discuss our Term Loan and Senior Notes in Note 8, Debt, to our Consolidated Financial Statements.

(Loss) Gain on Derivatives, net included a loss of approximately $60.8 million for the first six months of 2018 as compared to a gain of $18.8 million for the same period in 2017. The loss recorded for the first six months of 2018 included cash payments for commodity derivatives of $6.9 million while the gain incurred in the first six months of 2017 included cash payments of approximately $5.5 million for commodity derivatives. Changes related to our commodity derivatives were attributable to the volatility of natural gas, NGL and oil commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher natural gas, NGL and oil prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of gas, NGL and oil production volumes given the highly volatile gas, NGL and oil commodities market. In addition to our commodity derivatives, we incurred a loss of approximately $53.0 million related to our Term Loan embedded derivatives.

Other (Expense) Income for the first six months of 2018 includes approximately $13.9 million of professional and consulting fees related to restructuring and refinancing efforts incurred prior to our filing of the Bankruptcy Petition on May 18, 2018, and approximately $0.8 million of transaction fees paid in conjunction with the sale of our Westmoreland assets in March, 2018

Gain (Loss) on Extinguishments of Debt for the first six months of 2018 was zero. Loss on extinguishments of debt for the first six months of 2017 totaled approximately $3.0 million, which reflects the write-off of approximately $3.4 million of unamortized debt issuance costs related to the Senior Credit Facility retired in April 2017, offset by approximately $0.4 million in gains from debt to equity exchanges with certain holders of our Senior Notes. We discuss the debt to equity exchanges in Note 7, Long-Term Debt, to our Consolidated Financial Statements.

Reorganization Items, Net for the first six months of 2018 includes reorganization items as defined in ASC 852, Reorganizations. The reorganization items include both items of income and expense, netting to a net Other Income of approximately $28.6 million for the six months ending June 30, 2018. See discussion of Reorganization Items, Net, in Note 2 to our consolidated financial statements for additional details of the reorganization items.

Income Tax Expense for continuing operations for the first six months of 2018 and 2017 was zero, due to the full valuation allowances we maintain against our net deferred tax assets.

Net Income (Loss) Attributable to Rex Energy for the first six months of 2018 was a loss of approximately $72.5 million, as compared to a loss of $6.9 million for the same period in 2017 as a result of factors discussed above.

EBITDAX (Non-GAAP) from operations increased approximately $26.9 million to $54.9 million for the six month period ended June 30, 2018, as compared to the same period in 2017. The increase in EBITDAX can be primarily attributed to the increased production volumes for natural gas, NGLs and condensate, resulting in increased operating revenues and add backs of loss on derivatives, interest, and non-recurring items, which are higher than the prior year.

LOE per Mcfe measures the average cost of extracting natural gas, NGLs and condensate from our reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our natural gas and NGL reserves in the ground. LOE per Mcfe decreased $0.16 to $1.66 for the three months ended June 30, 2018 as compared to $1.82 for the same period in 2017. LOE per Mcfe decreased $0.16 to $1.68 for the six month period ended June 30, 2018 as compared to $1.84 for the same period in 2017. Our LOE is largely composed of variable type costs such as transportation, marketing, processing and gathering. For the second quarter of 2018, transportation, capacity and processing fees accounted for approximately 88.8% of our total Production and Lease Operating Expense as compared to 89.9% during the same period of 2017. For the six month period ended June 30, 2018, transportation, capacity and processing fees accounted for approximately 88.6% of our total Production and Lease Operating Expense as compared to 90.4% during the same period of 2017. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered into include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

Our G&A expenses include fees for well operating services, marketing, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our G&A expenses in relation to our production because these expenses have a direct impact on our profitability. G&A expenses per Mcfe were approximately $0.20 for the three month period ended June 30, 2018, as compared to $0.27 for the same period in 2017. The increases in G&A costs in 2018 is due primarily to employee costs. G&A expenses per Mcfe were approximately $0.26 for the six month period ended June 30, 2018, as compared to $0.28 for the same period in 2017. The increases in G&A costs in 2018 is due primarily to employee costs and non-cash compensation expense.

We have secured a financing commitment of $100 million from our former first lien term loan lenders, which, combined with our normal operating cash flow, will allow us to maintain normal operations and meet our ongoing financial commitments. Since the Petition Date numerous filings have been approved by the Bankruptcy Court to allow us to uphold commitments to our stakeholders, including employees, vendors and service providers, gathering and processing partners, and royalty owners.

On May 23, 2018, we executed a debtor-in-possession term loan credit agreement (the “DIP Facility”), with Angelo, Gordon Energy Servicer, LLC, as administrative and collateral agent. The DIP Facility provides $100 million in liquidity to continue our normal operations. As of June 30, 2018, we had drawn $35 million from the DIP Facility with $65 million remaining undrawn. On July 11, 2018, the Bankruptcy Court approved the final financing order providing us with access to the remaining $65 million of liquidity.

Our primary needs for cash are for the exploration, development and acquisition of gas and oil properties. During the six months ended June 30, 2018, we spent $101.0 million of capital on asset acquisitions, drilling projects, facilities and related equipment and acquisitions of unproved acreage. We funded our capital program with proceeds from the sale of our Westmoreland County assets, proceeds from the Term Loan and DIP Facility, and cash from operations.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for natural gas, NGLs and oil are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, we have primarily used cash flows from operations, borrowings from lines of credit and net proceeds from debt and equity offerings to fund the exploration and development of our gas and oil interests. As of June 30, 2018, we had approximately $28.8 million of unrestricted cash on hand and outstanding borrowings under our Term Loan of approximately $261.3 million with an additional $35.0 million of borrowing under the DIP Facility.

Our ability to fund our capital expenditure program is dependent upon the level of commodity prices and the success of our exploration programs in replacing our existing natural gas, NGL and condensate reserves. If commodity prices decrease, our operating cash flows may decrease, which could reduce funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives.

Due to the depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock (“Preferred Stock”). We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. In April and July 2017, we declared a quarterly dividend of $0.6 million, based on $150.00 per share on our Preferred Stock ($1.50 per depositary share, each representing 1/100 interest in a share of Preferred Stock) payable on May 15, 2017 and August 15, 2017, respectively; each dividend payment was applied to the earliest dividend in arrears at the time of payment. In October 2017and January 2018, we declared a quarterly dividend in the same amount; these dividend payments were paid in stock on November 15, 2017 and February 15, 2018, respectively, and were applied to the earliest dividend still in arrears at the time of payment. Any subsequent quarterly dividends declared and paid will be applied to the earliest dividend then in arrears until the arrearage is satisfied and dividends are current. In April 2018, we again suspended payment of our quarterly dividend on our Preferred Stock. As a result of having dividends in arrears on our Preferred Stock, we are not currently eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register public offerings of securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital.

In connection with certain of our marketing, transportation and processing agreements, we may be obligated to pay minimum fees of $219.4 million over the next five years, depending on our levels of production. In connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $363.1 million over the life of the agreements, which range from two to 20 years. These guarantees will decrease over time as the commitments are satisfied.

Our DIP Facility contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. Our financial covenants require us to maintain a minimum liquidity of $10.0 million at all times and a minimum “PDP Coverage Ratio” of 1.25 to 1.00. Failure to comply with these covenants could have a material adverse effect on our business. As of June 30, 2018 , our PDP Coverage Ratio was 1.85 to 1.00 and our liquidity was approximately $88.8 million. If an event of default under our Term Loan occurs and remains uncured, among other things, the lenders thereunder:

Although we have filed for protection under Chapter 11 of the U.S. Bankruptcy Code, there can be no assurances that we will be able to reorganize our capital structure on terms acceptable to us, our creditors, or at all.

Financial Condition and Cash Flows for the six months ended June 30, 2018 and 2017

The following table summarizes our sources and uses of funds for the periods noted:

Net cash provided by operating activities during the first six months of 2018 increased $7.8 million as compared to the same period in 2017. This was primarily due to increases in accounts payable and losses on derivatives, partially offset by non-cash reorganization expense items and an increase in accounts receivables.

Net cash used in investing activities during the first six months of 2018 increased $53.3 million as compared to the same period in 2017. This was primarily due to capital development expenditures in the first six months of 2018 of approximately $100.1 million, which was $46.1 million higher than in the same period of 2017, coupled with a decrease in proceeds from the sale of oil and gas properties and assets of approximately $8.1 million as compared to the same period in 2017.

Net cash provided by financing activities during the first six months of 2018 increased by approximately $83.0 million during the same period in 2017, primarily due to borrowings made on our Senior Secured Debtor-In-Possession Term Loan and our Term Loan.

As market conditions warrant and subject to our contractual restrictions in the Term Loan, our Indentures or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Our results of operations and cash flows are affected by changing natural gas, NGL and oil prices. If the price of natural gas, NGLs and oil increases or decreases, there could be a corresponding increase or decrease in the operating cost that we are required to bear for operations, as well as an increase or decrease in revenues.

During the quarter ended June 30, 2018, there were no material changes to the critical accounting policies previously reported by us in our Annual Report on Form 10-K for the year ended December 31, 2017. We describe critical recently adopted and issued accounting standards in Part I, Item 1. Financial Statements—Note 3, “Recently Issued Accounting Pronouncements.”

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.

The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented:

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of natural gas, NGLs and oil. We account for our natural gas and oil exploration and production activities under the successful efforts method of accounting. To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

For the three and six months ended June 30, 2018, we paid net settlements on natural gas, NGL and oil derivatives of approximately $4.9 million and $6.9 million, respectively, as compared to paying net settlements of approximately $2.1 million and $5.5 million for the same periods in 2017. These gains and losses are reported as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

Our primary sources of production and revenue are located in the Appalachian Basin. Natural gas prices in the Appalachian Basin are exposed to regional basis differentials when compared to NYMEX pricing. During the six months ended June 30, 2018, our average realized prices for natural gas were lower than the average NYMEX prices over the same period by approximately $0.34 per Mcf. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. We have Dominion South basis swaps in place for 6,680 MMcf at an average differential to Henry Hub NYMEX of $0.83 per Mcf for the remainder of 2018 in addition to Dominion South basis swaps for 12,775 MMcf at an average differential to Henry Hub NYMEX of $0.84 per Mcf for 2019. For the six months ended June 30, 2018, we paid cash settlements on our basis differential derivatives of approximately $1.7 million.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We have entered into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with our counterparties. While we do not obtain collateral to support the agreements, we do monitor the financial viability of our counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our natural gas, NGL and oil derivative positions at June 30, 2018, refer to Part I, Item 1. Financial Statements - Note 9, “Derivative Instruments and Fair Value Measurements”.

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. Our contractual obligations include long-term debt, operating leases, operational commitments, other loans and notes payable, derivative obligations, firm commitments under sales, gathering and processing agreements and asset retirement obligations. Since December 31, 2017, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our borrowings our Term Loan. See Part I, Item 1. Financial Statements—Note 8, “Debt” for additional information on the Senior Credit Facility and Term Loan.

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

We are exposed to various market risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, natural gas, NGLs and oil. Conversely, increases in the market prices for natural gas, NGLs and oil can have a favorable impact on our financial condition, results of operations and capital resources. Based on production through June 30, 2018, we project that a 10% decline in the price per barrel of NGLs and oil and the price per Mcf of gas from the first six months of 2018 average would reduce our gross revenues, before the effects of derivatives, for the remaining six months of 2018 by approximately $28.0 million.

We have designed our hedging program to reduce the risk of price volatility for our production in the natural gas, NGL and oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include swaps, collars, put options, basis swaps, and three way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in natural

gas, NGL and oil prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of natural gas, NGLs and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		85,750	Bbls	$	—	$	—	$	—	$	57.47		$	(817	)
2018 - Three-Way Collars		42,000	Bbls		41.82		51.09		60.75		—			(413	)
2019 - Swaps		118,000	Bbls		—		—		—		55.89			(1,231	)
2019 - Collars		18,000	Bbls		—		45.00		55.80		—			(125	)
2019 - Three-Way Collars		42,000	Bbls		38.57		48.57		58.86		—			(375	)
2020 - Swaps		24,000	Bbls		—		—		—		51.00			(304	)
2020 - Collars		22,500	Bbls				45.00		55.80					(167	)
2020 - Three-Way Collars		21,500	Bbls		38.95		48.95		60.22		—			(103	)
2021 - Swaps		6,000	Bbls		—		—		—		51.00			(76	)
2021 - Collars		16,500	Bbls		—		45.00		55.80		—			(125	)
2021 - Three-Way Collars		62,500	Bbls		37.44		47.04		57.98		—			(240	)
2022 - Three-Way Collars		23,000	Bbls		39.35		49.35		60.43		—			(60	)
		481,750	Bbls										$	(4,037	)
Natural Gas
2018 - Swaps		12,127,500	Mcf		—		—		—		2.98		$	394
2018 - Three-Way Collars		4,260,000	Mcf		2.31		2.88		3.55		—			310
2018 - Calls		2,920,000	Mcf		—		—		3.97		—			(19	)
2018 - Collars		2,222,500	Mcf		—		2.60		3.04		—			(134	)
2018 - Basis Swaps - Dominion South		9,808,000	Mcf		—		—		—		(0.83	)		(1,858	)
2018 - Basis Swaps - Texas Gas		7,360,000	Mcf		—		—		—		(0.13	)		324
2019 - Swaps		7,500,000	Mcf		—		—		—		2.91			129
2019 - Three-Way Collars		8,045,000	Mcf		2.35		2.81		3.43		—			313
2019 - Collars		4,471,750	Mcf		—		2.62		3.03		—			(227	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,725	)
2020 - Swaps		4,642,500	Mcf		—		—		—		2.90			242
2020 - Three-Way Collars		4,935,000	Mcf		2.33		2.77		3.31		—			350
2020 - Collars		2,645,000	Mcf		—		2.65		3.03		—			(34	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(2,068	)
2021 - Swaps		900,000	Mcf		—		—		—		2.90			59
2021 - Three-Way Collars		1,346,250	Mcf		2.32		2.74		3.20		—			97
2021 - Collars		792,500	Mcf		—		2.65		3.05		—			43
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2022 - Collars		147,500	Mcf		—		2.65		3.05		—			11
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(185	)
		108,818,500	Mcf										$	(6,533	)
NGLs
2018 - C3+ NGL Swaps		640,036	Bbls		—		—		—		33.06		$	(8,150	)
2018 - Ethane Swaps		780,000	Bbls		—		—		—		12.13			(450	)
2019 - C3+ NGL Swaps		570,814	Bbls		—		—		—		30.90			(4,524	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(964	)
2019 - Ethane Swaps		1,264,750	Bbls		—		—		—		12.60			322
2020 - C3+ NGL Swaps		191,112	Bbls		—		—		—		32.22			(1,875	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(241	)
2020 - Ethane Swaps		1,007,750	Bbls		—		—		—		12.31			(73	)
2021 - C3+ NGL Swap		88,404	Bbls		—		—		—		41.70			(599	)
2021 - Ethane Swaps		724,000	Bbls		—		—		—		12.27			(98	)
2022 - C3+ NGL Swap		9,420	Bbls		—		—		—		50.50			(33	)
2022 - Ethane Swaps		352,250	Bbls		—		—		—		12.27			(107	)
		5,769,836	Bbls										$	(16,791	)

We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR and prime rate based, as determined by our lenders, and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on our obligations. As of June 30, 2018, we did not have any interest rate derivatives in place, however we do from time to time enter interest rate derivatives to manage our interest rate exposure. We did not have any interest rate derivatives in place as of December 31, 2017. Based on our total debt as of June 30, 2018, of approximately $906.2 million, a 1.0% change in interest rates would impact our interest expense by approximately $9.1 million.

We maintain disclosure controls and procedures that are designed to ensure that that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), to allow timely decisions regarding required disclosure.

Our management (with the participation of our CEO and CFO) has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our CEO and CFO have concluded that, as of June 30, 2018, our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the quarter ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management, including our CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well-crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been, or will be, detected.

The information set forth under the subsections Legal Reserves and Environmental in Note 13, Commitments and Contingencies, to our Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q is incorporated herein by reference.

The following is an update to, and should be read in conjunction with Item 1A. Risk Factors, contained in our Annual Report on Form 10-K for the year ended December 31, 2017. In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2017, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

As a result of the filing of the Bankruptcy Petitions, we are subject to the risks and uncertainties associated with bankruptcy proceedings, and operating under Chapter 11 may restrict our ability to pursue strategic and operational initiatives.

For the duration of our pending Chapter 11 proceedings, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include:

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with our pending Chapter 11 proceedings could adversely affect our relationships with our suppliers, customers and employees. In particular, critical vendors may determine not to do business with us due to the filing of our Bankruptcy Petitions and our pending Chapter 11 proceedings, and we may not be successful in securing alternative sources. Because of the risks and uncertainties associated with our pending Chapter 11 proceedings, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 reorganization process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

Under Chapter 11 of the Bankruptcy Code, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of any current or future debtor-in-possession financing arrangement that we may enter into may require us to comply with certain financial maintenance covenants. Any such debtor-in-possession financing arrangement also may contain affirmative and negative covenants, which may include restrictions on (i) indebtedness, (ii) liens and guaranties, (iii) liquidations, mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) sanctions and anti-corruption matters, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, and (xii) hedging transactions. In addition, such debtor-in-possession financing arrangements may contain milestones relating to our Chapter 11 proceedings. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could result in an event of default under any such debtor-in-possession financing arrangements.

Trading in our securities during the pendency of our Chapter 11 proceedings is highly speculative and poses substantial risks. We expect that the existing common stock of the Company will be extinguished and existing equity holders will not receive consideration in respect of their equity interests.

If a Plan is approved in the Chapter 11 proceedings, it is likely that our existing common stock will be extinguished, and existing equity holders will likely not receive consideration in respect of their existing equity interests. As a result, trading in our common stock during the pendency of our Chapter 11 proceedings is highly speculative and involves substantial risks. Our common stock has been quoted on the OTC Markets Group’s Pink marketplace, but this may not always be the case. We could experience significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell shares of our common stock.

The pursuit of our Chapter 11 reorganization has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

While our Chapter 11 proceedings are pending, our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, on our financial condition and results of operations, particularly if the Chapter 11 proceedings are protracted.

During the pendency of our Chapter 11 proceedings, our employees will face considerable distraction and uncertainty, and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a materially adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

Our Chapter 11 proceedings contemplate a possible sale of the Company or certain of our material assets pursuant to Section 363 of the Bankruptcy Code or in connection with a Plan.

In order to successfully emerge from Chapter 11 bankruptcy protection, we must obtain confirmation of a Chapter 11 Plan by the Bankruptcy Court. If confirmation by the Bankruptcy Court does not occur, or if the Bankruptcy Court otherwise approves, the Company or certain of its material assets may be sold pursuant to Section 363 of the Bankruptcy Code. The Company has been in discussions with various third parties who may be interested in purchasing some or all of the assets of the Rex Debtors through the bankruptcy process, either through a sale pursuant to Section 363 of Chapter 11 of the Bankruptcy Code or in connection with a Plan. At this time, it is not possible to predict accurately the effect of the Chapter 11 reorganization process on our business, creditors or stockholders, when the Rex Debtors may emerge from Chapter 11 or what the disposition will be of any claims against the Rex Debtors. Our future results depend on the timely and successful confirmation and implementation of a Plan.

There can be no assurance that our current cash position and amounts of cash from future operations will be sufficient to fund operations. In the event that we do not have sufficient cash to meet our liquidity requirements, and our current financing is insufficient or exit financing is not available, we may be required to seek additional financing. There can be no assurance that such additional financing would be available, or, if available, would be available on acceptable terms. Failure to secure any necessary exit financing or additional financing would have a material adverse effect on our operations and ability to continue as a going concern.

Our post-bankruptcy capital structure has yet to be determined, and any changes to our capital structure may have a material adverse effect on existing debt and security holders.

Our capital structure will be set pursuant to a Plan that requires Bankruptcy Court approval. Any reorganization of our capital structure may include exchanges of new debt or equity securities for our existing debt and equity securities, and such new debt or equity securities may be issued at different interest rates, payment schedules and maturities than our existing creditors. The success of a reorganization through any such exchanges or modifications will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification, and there can be no guarantee of success. If such exchanges or modifications are successful, holders of our debt may find their holdings no longer have any value or are materially reduced in value, or they may be converted to equity and be diluted or may be modified or replaced by debt with a principal amount that is less than the outstanding principal amount, longer maturities and reduced interest rates. There can be no assurance that any new debt or equity securities will maintain their value at the time of issuance.

Any Plan that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or adverse market conditions persist or worsen, our Plan may be unsuccessful in its execution.

Any Plan that we may implement will affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the United States and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, any Plan will rely upon financial projections. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any Plan we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any Plan.

As a result of the pending Chapter 11 proceedings, realization of assets and liquidation of liabilities are subject to uncertainty, and our historical financial information will not be indicative of our future financial performance.

Our capital structure will likely be significantly altered under any Plan ultimately confirmed by the Bankruptcy Court. Under fresh-start reporting rules that may apply to us upon the effective date of a Plan, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a Plan could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements. In connection with our Chapter 11 proceedings and the development of a Plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such sales, disposals, liquidations, settlements or charges could be material to our consolidated financial position and results of operations in any given period.

We may be unable to comply with restrictions imposed by any current or future debtor-in-possession financing arrangement and any other financing arrangements.

The agreements governing our outstanding financing arrangements impose a number of restrictions on us. For example, the terms of our credit facilities, leases and other financing arrangements contain financial and other covenants that create limitations on our ability to borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt and require us to comply with various other financial covenants. The terms of any current or future debtor-in-possession financing arrangement that we may enter into may require us to comply with certain other financial maintenance covenants. Such debtor-in-possession financing arrangements may also contain affirmative and negative covenants, which may include restrictions on (i) indebtedness, (ii) liens and guaranties, (iii) liquidations, mergers, consolidations, acquisitions, (iv) disposition of assets or subsidiaries, (v) affiliate transactions, (vi) creation or ownership of certain subsidiaries, partnerships and joint ventures, (vii) continuation of or change in business, (viii) restricted payments, (ix) sanctions and anti-corruption matters, (x) no restriction in agreements on dividends or certain loans, (xi) loans and investments, and (xii) hedging transactions. In addition, such debtor-in-possession financing arrangements may contain milestones relating to the Chapter 11 proceedings. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply could result in an event of default under the debtor-in-possession financing arrangements or our other financing arrangements.

As of the date of this report, we are six quarters in arrears with respect to the payment of dividends on our Preferred Stock. As of the date of this report, accumulated dividends in arrears totaled approximately $3.6 million.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

	June 30, 2018 (in thousands)
Accounts Payable and Accrued Expenses	$	27,716
Accrued Interest Payable		30,043
Debt (See Note 8)		609,865
Liabilities Subject to Compromise	$	667,624

	Three and Six Months Ended June 30, 2018 (in thousands)
Legal and Professional Fees	$	(9,817	)
Unamortized Deferred Financing Balances (a)		43,509
Debtor-in Possession Financing Fees		(3,750	)
Effect of Early Hedge Terminations		(1,175	)
Other		(132	)
Reorganization Items, net	$	28,635

($ in Thousands)	June 30, 2018
Beginning Balance at January 1, 2018	$	9,939
Future Abandonment Obligation Incurred	$	137
Future Abandonment Obligation Settled	$	(156	)
Future Abandonment Obligation Cancelled or Sold	$	(877	)
Future Abandonment Obligation Revision of Estimated Obligation	$	99
Future Abandonment Obligation Accretion Expense	$	473
Total Future Abandonment Cost¹	$	9,616

				Fair Value Measurements at June 30, 2018
($ in Thousands)	Total Carrying Value as of June 30, 2018			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(24,911	)	$	—	$	(24,911	)	$	—

				Fair Value Measurements at December 31, 2017
($ in Thousands)	Total Carrying Value as of December 31, 2017			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(19,414	)	$	—	$	(19,414	)	$	—

			PAGE
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			3
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements	5
		Consolidated Balance Sheets as of June 30. 2018 (Unaudited) and December 31, 2017	5
		Consolidated Statements of Operations (Unaudited) for the three and six-month periods ended June 30, 2018 and June 30, 2017	6
		Consolidated Statement of Changes in Stockholders’ Equity (Unaudited) for the six-month period ended June 30, 2018	7
		Consolidated Statements of Cash Flows (Unaudited) for the six-month periods ended June 30, 2018 and June 30, 2017	8
		Notes to Consolidated Financial Statements (Unaudited)	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	44
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	61
	Item 4.	Controls and Procedures	63
PART II. OTHER INFORMATION			64
	Item 1.	Legal Proceedings	64
	Item 1A.	Risk Factors	64
	Item 6.	Exhibits	67
SIGNATURES			68

	Common Stock					Preferred Stock
	Shares			Par Value		Shares		Par Value		Additional Paid- In Capital		Accumulated Deficit			Total Stockholders’ Equity (Deficit)
BALANCE December 31, 2017		10,244		$	10		4	$	1	$	652,917	$	(706,490	)	$	(53,562	)
Equity Based Compensation		—			—		—		—		1,206		—			1,206
Issuance of Restricted Stock, Net of Forfeitures		(27	)		—		—		—		—		—			—
Preferred Dividends in Arrears Paid in Common Shares		491			1		—		—		598		(598	)		1
Net Loss		—			—		—		—		—		(72,476	)		(72,476	)
BALANCE June 30, 2018		10,708		$	11		4	$	1	$	654,721	$	(779,564	)	$	(124,831	)

	Three Months Ended June 30,				Six Months Ended June 30,
($ in Thousands)	2018		2017		2018		2017
Revenues from Contracts with Customers by Product
Natural Gas	$	29,705	$	29,097	$	59,387	$	60,442
NGLs		32,293		15,367		61,011		32,667
Condensate		13,157		2,993		19,782		6,413
Total	$	75,155	$	47,457	$	140,180	$	99,522

		June 30, 2018
		Secured Debt		Debt Balances included in Liabilities Subject to Compromise


Term Loan - due April 2020		$	261,315	$	—
Debtor-In-Possession Term Loan - due November 2018		$	35,000	$	—


8.875% Senior Notes due 2020		$	—	$	7,333
6.25% Senior Notes due 2022			—		5,363
1% / 8% Second Lien Senior Notes due 2020			—		587,606
	Total Senior Notes	$	—	$	600,302

Long-Term Capital Leases - Equipment Financing
	Due March, 2021	$	—	$	557
	Due June, 2021		—		1,254
	Due September, 2021		—		1,428
	Due May, 2022		—		6,324
	Total Capital Lease Obligations	$	—	$	9,563
	Debt Balances Subject to Compromise	$	—	$	609,865

		Outstanding				Exercisable
Exercise Price		Number Outstanding at June 30, 2018		Weighted-Average Exercise Price		Number Exercisable at June 30, 2018		Weighted-Average Exercise Price
	9.70		2,667	$	9.70		1,835	$	9.70
	16.90		57,169	$	16.90		38,118	$	16.90
	49.00		4,000	$	49.00		4,000	$	49.00
	50.40		3,070	$	50.40		3,070	$	50.40
	104.20		2,217	$	104.20		2,217	$	104.20
			69,123	$	22.77		49,240	$	25.26

	Six Months Ended June 30, 2018	Year Ended December 31, 2017
Expected Dividend Yield	0.0%	0%
Risk-Free Interest Rate	1.0%	1.0%
Expected Volatility – Rex Energy	58.6%	58.6%
Expected Volatility – Peer Group	29.8%-85.0%	29.8%-85.0%
Market Index	35.6%	35.6%
Expected Life	Three Years	Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2017		200,475		$	13.62
Awards		—			—
Forfeitures		(27,817	)		15.13
Vested		(56,976	)		24.72
Restricted stock awards, as of June 30, 2018	$	115,682		$	7.79

($ in Thousands)
2018	$	488
2019		903
2020		802
2021		484
2022		496
Thereafter		—
Total	$	3,173

($ in Thousands)
2018	$	25,597
2019		51,096
2020		49,724
2021		46,729
2022		46,260
Thereafter		390,656
Total	$	610,062

Calendar Quarter Ending	West Texas Intermediate ("WTI") Average Price per Bbl (a)
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

(in thousands, except per share amounts)	Three Months Ended June 30,						Six Months Ended June 30,
Numerator:	2018			2017			2018			2017
Net Loss	$	(2,684	)	$	(9,603	)	$	(72,476	)	$	(6,920	)
Less: Preferred Stock Dividends		(598	)		(598	)		(1,196	)		(1,196	)
Net Loss Attributable to Common Shareholders	$	(3,282	)	$	(10,201	)	$	(73,672	)	$	(8,116	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		10,708			9,881			10,587			9,825
Effect of Dilutive Securities:
Employee Stock Options		—			—			—			—
Employee Performance-Based Restricted Stock Awards		—			—			—			—
Effect of Assumed Conversions of Preferred Stock		—			—			—			—
Weighted Average Common Shares Outstanding - Diluted		10,708			9,881			10,587			9,825
Earnings per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Net Loss Attributable to Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)
Diluted — Net Loss Attributable to Common Shareholders	$	(0.31	)	$	(1.03	)	$	(6.96	)	$	(0.83	)

	Production and Revenue by Product
	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
Revenue – Natural Gas(a)	$	29,705,301	$	29,097,041	$	59,387,066	$	60,441,673
Volumes (Mcf)		11,996,504		9,889,888		23,011,737		19,801,630
Average Price	$	2.48	$	2.94	$	2.58	$	3.05
Revenue – Condensate (a)	$	13,157,165	$	2,993,340	$	19,781,825	$	6,413,513
Volumes (Bbl)		210,656		70,687		326,539		144,927
Average Price	$	62.46	$	42.35	$	60.58	$	44.25
Revenue – C3+ NGLs(a)	$	22,753,935	$	10,119,239	$	43,256,298	$	23,126,667
Volumes (Bbl)		599,383		439,441		1,146,891		861,146
Average Price	$	37.96	$	23.03	$	37.72	$	26.86
Revenue – Ethane(a)	$	9,538,821	$	5,247,189	$	17,755,112	$	9,540,190
Volumes (Bbl)		855,119		526,893		1,667,813		979,580
Average Price	$	11.15	$	9.96	$	10.65	$	9.74
Average Production Cost per Mcfe(b)	$	1.66	$	1.82	$	1.68	$	1.84

	Other Performance Measurements
	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
EBITDAX from Continuing Operations ($ in Thousands) (a)	$	30,398	$	12,420	$	54,924	$	27,996
LOE per Mcfe	$	1.67	$	1.82	$	1.69	$	1.84
G&A per Mcfe	$	0.20	$	0.27	$	0.26	$	0.28

	REX ENERGY CORPORATION (Registrant)
Date: August 8, 2018	By:	/s/ *Thomas C. Stabley*
		Thomas C. Stabley
		Chief Executive Officer (Principal Executive Officer)

This ‘10-Q’ Filing	Date	Other Filings

	7/4/22
	7/15/19
	6/30/19
	12/15/18
	11/18/18
	11/14/18	15-12B, 8-K
	8/23/18
Filed on:	8/8/18
	8/6/18
	8/1/18
	7/25/18
	7/11/18
	7/2/18
For Period end:	6/30/18
	6/29/18
	6/1/18
	5/29/18
	5/23/18	4
	5/18/18	8-K, DEF 14A
	5/15/18	10-Q
	5/3/18	8-K
	4/27/18	8-K
	4/19/18	25-NSE
	4/12/18	8-K
	4/10/18
	4/3/18	8-K, NT 10-K
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	3/31/18	10-Q
	3/23/18
	3/21/18
	3/13/18	8-K
	2/15/18
	1/1/18
	12/31/17	10-K, NT 10-K
	12/22/17
	12/15/17
	11/15/17
	8/15/17
	7/5/17
	6/30/17	10-Q
	5/15/17	8-K
	5/12/17	8-K
	5/5/17	8-K, DEF 14A, PRE 14A
	4/28/17	8-K
	3/31/17	10-Q
	1/11/17	8-K
	12/31/16	10-K
	11/15/16
	10/1/16	4
	8/15/16
	6/14/16	8-K
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	3/31/16	10-Q, 8-K
	3/1/16	4, 8-K
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	12/31/15	10-K
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