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3: EX-10.04 Material Contract HTML 141K
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6: EX-31.02 Certification -- §302 - SOA'02 HTML 26K
7: EX-32 Certification -- §906 - SOA'02 HTML 21K
14: R1 Cover Page HTML 72K
15: R2 Statements of Condensed Consolidated Operations HTML 157K
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16: R3 Statements of Condensed Consolidated Comprehensive HTML 61K
Income (Loss) (Unaudited)
17: R4 Statements of Condensed Consolidated Comprehensive HTML 27K
Income (Loss) (Unaudited) (Parenthetical)
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25: R12 Discontinued Operations HTML 59K
26: R13 Revenue from Contracts with Customers HTML 71K
27: R14 Derivative Instruments HTML 62K
28: R15 Fair Value Measurements HTML 58K
29: R16 Income Taxes HTML 25K
30: R17 Debt HTML 30K
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(Exact Name of Registrant as Specified in its Charter)
iPennsylvania
i25-0464690
(State
or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)
i625 Liberty Avenue, Suite 1700
iPittsburgh,
iPennsylvaniai15222
(Address of principal executive offices and zip code)
(i412)
i553-5700
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name
of each exchange on which registered
iCommon Stock, no par value
iEQT
iNew
York Stock Exchange
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. iYes☒ No ☐
Indicate
by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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-2 of the Exchange Act.
iLarge
accelerated filer
☒
Accelerated filer
☐
Emerging growth company
i☐
Non-accelerated filer
☐
Smaller
reporting company
i☐
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 i☐ No ☒
Other
post-retirement benefits liability adjustment (c)
i76
i86
i152
i172
Change
in accounting principle (d)
i—
i—
(i496
)
i—
Other
comprehensive income (loss)
i118
(i344
)
(i260
)
(i501
)
Comprehensive
income (loss)
i125,684
i136,002
i315,997
(i1,309,134
)
Less:
Comprehensive income from discontinued operations attributable to noncontrolling interests
i—
i118,540
i—
i259,555
Comprehensive
income (loss) attributable to EQT Corporation
$
i125,684
$
i17,462
$
i315,997
$
(i1,568,689
)
(a)
Net
of tax benefit of $(i163) for the three months ended June 30, 2018 and $(i263)
for the six months ended June 30, 2018.
(b)
Net of tax expense of $i10 and $i26
for the three months ended June 30, 2019 and 2018, respectively, and $i20 and $i44
for the six months ended June 30, 2019 and 2018, respectively.
(c)
Net of tax expense of $i26
and $i30 for the three months ended June 30, 2019 and 2018, respectively, and $i52
and $i60 for the six months ended June 30, 2019 and 2018, respectively.
(d)
Related
to adoption of Accounting Standard Update (ASU) 2018-02. See Note 1 for additional information.
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
Common
shares authorized: i320,000 shares. Preferred shares authorized: i3,000 shares. There are ino
preferred shares issued or outstanding.
(a)
Net of tax benefit of $(i163).
(b)
Net
of tax expense of $i26 for the three months ended June 30, 2018 and $i10
for the three months ended June 30, 2019.
(c)
Net of tax expense of $i30 for the three
months ended June 30, 2018 and $i26 for the three months ended June 30, 2019.
(d)
Dividends
were $i0.03 per share for both periods.
(e)
Distributions to noncontrolling interests were $i1.065,
$i0.258, and $i0.3049
per common unit from EQM Midstream Partners, LP (EQM), EQGP Holdings, LP (EQGP) and Rice Midstream Partners LP (RMP), respectively.
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
1.iFinancial
Statements
The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Quarterly Report on Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of June 30, 2019
and December 31, 2018, the results of its operations and equity for the three and six month periods ended June 30, 2019 and 2018 and its cash flows for the six month periods ended June 30, 2019 and 2018. Certain previously reported amounts have been reclassified to conform to the current year presentation. In this Quarterly Report on Form 10-Q, references to “we,”“us,”“our,”“EQT,”“EQT Corporation,” and the “Company” refer collectively to EQT Corporation and its consolidated subsidiaries.
The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. Additionally, the Condensed Consolidated Financial Statements have been recast to reflect the presentation of discontinued operations as a result of the Separation and Distribution defined and described in Note 2.
For further
information, refer to the consolidated financial statements and related footnotes as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.
Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, Leases. The standard required entities to record assets and liabilities for contracts
currently recognized as operating leases. In July 2018, the FASB issued ASU 2018-11, Leases: Targeted Improvements. The update provided an optional transition method of adoption that permitted entities to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Under the optional transition method, comparative financial information and disclosures are not required. The update also provided transition practical expedients. The standard required disclosures of the nature, maturity and value of an entity's lease liabilities and elections made by the entity. In March 2019, the FASB issued ASU 2019-01, Leases: Codification Improvements, which, among other things, clarified interim disclosure requirements in the year of ASU 2016-02 adoption.
The
Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company implemented a new lease accounting system to monitor its population of lease contracts. The Company also implemented processes and controls to review both new contracts and modifications to existing contracts that contain lease components for appropriate accounting treatment and to generate disclosures required under the standards. For the disclosures
required by the standards, see Note 10.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the probable initial recognition threshold in current GAAP and requires an entity to reflect its current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This ASU will be effective
for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. The Company is currently evaluating the impact this standard will have on its financial statements and related disclosures.
In February 2018, the FASB issued ASU 2018-02, Income Statement—Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU allows companies to reclassify stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017 (the Tax Cuts and Jobs Act) from accumulated other comprehensive income to retained earnings. This ASU is effective for fiscal years beginning after December
15, 2018 and early adoption is permitted. The reclassification permitted under this ASU should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized.
Notes to Condensed Consolidated Financial Statements (Unaudited)
The
Company adopted this ASU on January 1, 2019 which resulted in a $i0.5 million decrease to other comprehensive income and increase to retained earnings.
In
August 2018, the FASB issued ASU 2018-13, Fair Value Measurement, Changes to the Disclosure Requirements for Fair Value Measurement, which makes a number of changes to the hierarchy associated with Level 1, 2 and 3 fair value measurements and the related disclosure requirements. This guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the effect this standard will have on its financial statements and related disclosures but does not expect the adoption of this standard to have a material impact on its financial statements and related disclosures.
2.iDiscontinued Operations
On November 12, 2018, the Company completed the previously announced separation of its midstream business, which was composed of the separately operated natural gas gathering, transmission and storage, and water services businesses of the
Company, from its upstream business, which is composed of the natural gas, oil and natural gas liquids (NGLs) development, production and sales and commercial operations of the Company (the Separation). The Separation was effected by the transfer of the midstream business from the Company to Equitrans Midstream Corporation (Equitrans Midstream) and the distribution of i80.1%
of the outstanding shares of Equitrans Midstream common stock to the Company's shareholders (the Distribution).
The Company retained i19.9% of the outstanding shares of Equitrans Midstream common stock. The
Company does not have the ability to exercise significant influence and does not have a controlling financial interest in Equitrans Midstream or any of its subsidiaries. As such, this investment is accounted for as an investment in equity securities. As of June 30, 2019 and December 31, 2018, the fair value was based on the closing stock price of Equitrans Midstream multiplied by the number of shares of common stock owned by the Company. The changes in fair value were recorded in the Statements of Condensed Consolidated Operations.
Equitrans
Midstream included all of the Company's former EQM Gathering, EQM Transmission and EQM Water segments. For all periods prior to the Separation and Distribution, the results of operations of Equitrans Midstream are reflected as discontinued operations. The Statements of Condensed Consolidated Operations have been recast to reflect this presentation and also included the presentation of certain transportation and processing expenses in continuing operations which were previously eliminated in consolidation. The cash flows related to Equitrans Midstream have not been segregated and are included within the Statements of Condensed Consolidated Cash Flows for all periods prior to the Separation and Distribution.
i
The
results of operations of Equitrans Midstream presented as discontinued operations in the Statements of Condensed Consolidated Operations are summarized below. The Company allocated all of the transaction costs associated with the Separation and Distribution and a portion of the costs associated with the acquisition of Rice Energy Inc. to discontinued operations.
Notes to Condensed Consolidated Financial Statements (Unaudited)
The following table presents amounts of the discontinued operations related to Equitrans Midstream for cash flows from operating activities which are included and not separately stated in the Statements of Condensed Consolidated Cash Flows. Cash flows from investing and financing are separately stated in the Statements of Condensed Consolidated Cash Flows.
Under the Company's natural gas, oil and NGLs sales contracts, the Company generally considers the delivery
of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery. These contracts typically require payment within i25 days of the end of the calendar month in which the gas is delivered. A significant number of these contracts contain variable
consideration because the payment terms refer to market prices at future delivery dates. In these situations, the Company has not identified a standalone selling price because the terms of the variable payments relate specifically to the Company’s efforts to satisfy the performance obligations. Other contracts contain fixed consideration (i.e. fixed price contracts or contracts with a fixed differential to New York Mercantile Exchange (NYMEX) or index prices). The fixed consideration is allocated to each performance obligation on a relative
standalone selling price basis, which requires judgment from management. For these contracts, the Company generally concludes that the fixed price or fixed differentials in the contracts are representative of the standalone selling price.
Based on management’s judgment, the performance obligations for the sale of natural gas, oil and NGLs are satisfied at a point in time because the customer obtains control and legal title of the asset when the natural gas, oil or NGLs are delivered to the designated sales point.
The sales
of natural gas, oil and NGLs as presented on the Statements of Condensed Consolidated Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling natural gas, oil and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.
Because the Company's performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company has recognized
amounts due from contracts with customers of $i360.8 million and $i783.0
million as accounts receivable within the Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018, respectively. Accounts receivable also includes amounts due from joint interest partners as well as amounts due for settled derivative instruments.
i
The table
below provides disaggregated information regarding the Company’s revenues. Certain contracts that provide for the release of capacity that is not used to transport the Company’s produced volumes were deemed to be outside the scope of ASU 2014-09, Revenue from Contracts with Customers. The cost of, and recoveries on, that capacity are reported within net marketing services and other. Derivative contracts are also outside the scope of Revenue from Contracts
with Customers.
Gain
(loss) on derivatives not designated as hedges
i407,635
(i53,897
)
i275,639
i8,695
Total
operating revenues
$
i1,310,252
$
i950,648
$
i2,453,425
$
i2,262,684
i
The
following table includes the transaction price allocated to the Company's remaining performance obligations on all contracts with fixed consideration as of June 30, 2019. The table excludes all contracts that qualified for the exception to the relative standalone selling price method.
2019
(a)
2020
2021
Total
(Thousands)
Natural gas sales
$
i24,695
$
i51,299
$
i9,209
$
i85,203
/
(a)
July
1 through December 31.
4.iDerivative Instruments
The
Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company. The Company utilizes derivative commodity instruments to hedge its cash flows from sales of the Company's produced natural gas and NGLs. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
The derivative commodity instruments currently utilized by the
Company are primarily swap agreements, collar agreements and option agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company uses these agreements to hedge its NYMEX and basis exposure. The Company may also use other contractual agreements in implementing its commodity hedging strategy. The Company’s over the counter (OTC) derivative commodity instruments are typically entered into with financial institutions and the creditworthiness of all counterparties is regularly monitored.
The
Company does not designate any of its derivative instruments as cash flow hedges; therefore, all changes in fair value of the Company’s derivative instruments are recognized within operating revenues in the Statements of Condensed Consolidated Operations. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Contracts
which result in physical delivery of a commodity expected to be sold by the Company in the normal course of business are generally designated as normal sales and are exempt from derivative accounting. If contracts that result in the physical receipt or delivery of a commodity are not designated or do not meet all the criteria to qualify for the normal purchase and normal sale scope exception, the contracts are subject to derivative accounting.
OTC arrangements require settlement in cash. The Company also enters into exchange traded derivative
commodity instruments that are generally settled with offsetting positions. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Condensed Consolidated Cash Flows.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
With respect to the derivative commodity instruments held by the
Company, the Company hedged portions of expected sales of production and portions of its basis exposure covering approximately i2,371 Bcf of natural gas and i690
Mbbls of NGLs as of June 30, 2019, and i3,128 Bcf of natural gas and i1,505
Mbbls of NGLs as of December 31, 2018. The open positions at June 30, 2019 and December 31, 2018 had maturities extending through December 2024 for both periods.
When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the counterparty,
the counterparty requires the Company to remit funds as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to
the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Condensed Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018.
When the Company enters into exchange-traded natural gas contracts, exchanges may require
the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. The Company must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Condensed Consolidated Balance Sheets. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the
Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the related contract. The margin requirements are subject to change at the exchanges’ discretion. The Company recorded current assets of $i1.7
million and $i40.3 million as of June 30, 2019 and December 31, 2018, respectively, for such deposits in its Condensed Consolidated Balance Sheets.
The
Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. iiThe table below reflects the impact of netting
agreements and margin deposits on gross derivative assets and liabilities./
Gross derivative instruments, recorded in the Condensed Consolidated Balance Sheets
Derivative
instruments subject to master netting agreements
Certain
of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by S&P Global Ratings (S&P) or Moody’s Investors Service, Inc. (Moody’s) are lowered below investment grade, additional collateral must be deposited with the counterparty if the amounts outstanding on those contracts exceed certain thresholds. The additional collateral can be up to i100%
of the derivative liability. As of June 30, 2019, the aggregate fair value of all derivative instruments with credit risk-related contingent features that were in a net liability position was $i94.4 million, for which the Company had ino
collateral posted on June 30, 2019. If the Company’s credit rating by S&P or Moody’s had been downgraded to a rating immediately below investment grade on June 30, 2019, the Company would not have been required to post any additional collateral under the agreements with the respective counterparties. The required margin on the Company’s derivative instruments is subject to significant change as a result of factors other than credit rating, such as gas prices and credit thresholds set forth in agreements between the hedging counterparties
and the Company. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s senior unsecured debt was rated BBB- by S&P and Baa3 by Moody’s at June 30, 2019. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade. See also "Security Ratings and Financing Triggers" under Part I, Item 2, "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Notes to the Condensed Consolidated Financial Statements (Unaudited)
The Company may engage in interest rate swaps to hedge exposure to fluctuations in interest rates, but has not executed any interest rate swaps since 2011. Amounts related to historical interest rate
swaps are recorded in other comprehensive income (OCI). See Note 9.
5.iFair Value Measurements
The
Company records its financial instruments, principally derivative instruments, at fair value in its Condensed Consolidated Balance Sheets. The Company estimates the fair value using quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use market-based parameters as inputs, including forward curves, discount rates, volatilities and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of
the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk-free instrument and credit default swaps rates where available.
The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities in Level 2 primarily include the Company’s
swap, collar and option agreements.
Exchange traded commodity swaps are included in Level 1. The fair value of the commodity swaps included in Level 2 is based on standard industry income approach models that use significant observable inputs, including but not limited to NYMEX natural gas forward curves, LIBOR-based discount rates, basis forward curves and natural gas liquids forward curves. The Company’s collars and options are valued using standard industry income approach option models. The significant observable inputs utilized by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates. The NYMEX natural gas forward curves, LIBOR-based discount rates, natural gas volatilities, basis forward curves and NGLs forward curves are validated
to external sources at least monthly.
i
The table below reflects assets and liabilities measured at fair value on a recurring basis.
Gross
derivative instruments, recorded in the Condensed Consolidated Balance Sheets
The
carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturity of the instruments. The carrying value of the Company's investment in Equitrans Midstream approximates fair value as it is a publicly traded company. The carrying value of borrowings under the Company's credit facility and term loan facility approximate fair value as the interest rates are based on prevailing market rates. The Company considered all of these fair values to be Level 1 fair value measurements.
The Company
also has an immaterial investment in a fund that invests in companies developing technology and operating solutions for exploration and production companies for which it recognized a cumulative effect of accounting change in the first quarter 2018. The investment is valued using the net asset value as a practical expedient as provided in the financial statements received from fund managers.
The Company estimates the fair value of its Senior Notes using its established fair value methodology. As the Company's Senior Notes are not all actively traded, the fair value is a Level 2 fair value measurement. As of June 30, 2019
and December 31, 2018,
Notes to the Condensed Consolidated Financial Statements (Unaudited)
the estimated fair value of the Company's Senior Notes was approximately $i3.9
billion and $i4.4 billion, respectively, and the carrying value of the Company's Senior Notes was approximately $i3.9
billion and $i4.6 billion, respectively, inclusive of the current portion of debt on the Condensed Consolidated Balance Sheets. The fair value of the Company's note payable to EQM is a Level 3 fair value measurement which is estimated using an income approach model utilizing a market-based discount rate. As of June 30, 2019
and December 31, 2018, the estimated fair value of the Company's note payable to EQM was approximately $i130 million and $i122
million, respectively, and the carrying value of the Company's note payable to EQM was approximately $i112 million and $i115
million, respectively, inclusive of the current portion of debt on the Condensed Consolidated Balance Sheets.
The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. There were no transfers between Levels 1, 2 and 3 during the periods presented.
For information on the fair values of assets related to the impairments of proved and unproved oil and gas properties and of other long-lived assets, see Note 11 and Note 1 in the Company's Annual Report on Form 10-K for the
year ended December 31, 2018.
6.iIncome Taxes
For the six
months ended June 30, 2019 and 2018, the Company calculated the provision for income taxes by applying the annual effective tax rate for the full fiscal year to "ordinary" income or loss (pre-tax income or loss excluding unusual or infrequently occurring items) for the quarter. There were no material changes to the Company’s methodology for determining unrecognized tax benefits during the six months ended June 30, 2019.
The
Company recorded income tax expense at an effective tax rate of i19.6% for the six months ended June 30, 2019 and income tax benefit at an effective tax rate of i24.1%
for the six months ended June 30, 2018. The Company’s effective tax rate for the six months ended June 30, 2019 was lower than the statutory rate primarily due to the release of valuation allowances relating to the Company’s ability to utilize state net operating losses against future taxable income and the Alternative Minimum Tax (AMT) sequestration. The IRS announced in January 2019 that it was reversing its prior position that 6.2% of AMT refunds were subject to sequestration by the federal government. As a result, the
Company reversed this related valuation allowance in the first quarter of 2019. The Company’s effective tax rate for the six months ended June 30, 2018 was lower than the statutory rate primarily because the amount of benefit recorded at any interim period is limited to the amount of benefit that would be recognized if the year-to-date loss was the forecasted loss for the entire year.
7.iDebt
The
Company has a $i2.5 billion credit facility that expires in July 2022. The Company had ino
letters of credit outstanding under the credit facility as of June 30, 2019 and December 31, 2018. During the three months ended June 30, 2019 and 2018, the maximum amounts of outstanding borrowings at any time under the credit facility were $i0.6
billion and $i1.5 billion, respectively, the average daily balances were approximately $i0.3
billion and $i0.9 billion, respectively, and interest was incurred at weighted average annual interest rates of i4.0%
and i3.4%, respectively. During the six months ended June 30, 2019 and 2018, the maximum amounts of outstanding borrowings at any time under
the credit facility were $i1.1 billion and $i1.6
billion, respectively, the average daily balances were approximately $i0.5 billion and $i1.2
billion, respectively, and interest was incurred at weighted average annual interest rates of i4.0% and i3.2%,
respectively.
On May 31, 2019, the Company entered into a Term Loan Agreement (Term Loan Agreement) providing for a $i1.0 billion unsecured term loan facility (Term Loan Facility) and borrowed $i1.0
billion under the Term Loan Facility. The Company used the net proceeds to repay the $i700 million in aggregate principal amount of i8.125%
Senior Notes which matured on June 1, 2019, to repay outstanding borrowings under the Company’s $i2.5 billion credit facility and to pay accrued interest and fees and expenses related to the foregoing and the Term Loan Agreement. Remaining proceeds from
the borrowing were used by the Company for general corporate purposes. The Term Loan Facility matures on May 31, 2021.
At the Company’s election, the $i1.0
billion in borrowings under the Term Loan Facility bear interest at a eurodollar rate as defined in the Term Loan Agreement plus a margin determined on the basis of the Company’s credit ratings. This margin is i1.00% based on the
Company’s current credit ratings. The Company may voluntarily prepay borrowings under the Term Loan Facility, in whole or in part, without premium or penalty, but subject to reimbursement of funding losses with respect to prepayment. Borrowings under the Term Loan Facility that are repaid may not be reborrowed. The Company had $i1.0
billion of outstanding borrowings under the Term Loan Facility as of June 30, 2019 and interest was incurred at a weighted average annual interest rate of i3.4%.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
The Term Loan Agreement contains certain representations and warranties and various affirmative and negative covenants and events of default, including (i) a restriction on the ability of the Company or its subsidiaries to incur or permit liens on assets, subject to certain significant exceptions, (ii) the establishment of a maximum ratio of consolidated debt to total capital of the
Company and its subsidiaries such that consolidated debt shall at no time exceed i65% of total capital, (iii) a limitation on certain changes to the Company’s business, and (iv) certain restrictions related to mergers or acquisitions.
8.iEarnings Per Share
Potentially dilutive securities consisting of restricted stock awards included in the calculation of diluted earnings per share were i124,250
and i235,743 for the three and six months ended June 30, 2019, respectively, and i123,973
for the three months ended June 30, 2018. The Company reported a net loss for the six months ended June 30, 2018; therefore, all options and restricted stock were excluded from the calculation of diluted weighted average shares outstanding and diluted earnings per share because of their anti-dilutive effect on loss per share. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive were i1,885,529
for the three and six months ended June 30, 2019 and i1,201,900 and i1,283,753
for the three and six months ended June 30, 2018, respectively.
9. iChanges in Accumulated Other Comprehensive Income (Loss) by Component
i
The
following table explains the changes in accumulated OCI (loss) by component.
(Gains)
losses reclassified from accumulated OCI, net of tax related to natural gas cash flow hedges were reclassified into operating revenues. Losses from accumulated OCI, net of tax related to interest rate cash flow hedges were reclassified into interest expense.
(b)
This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31,
2018 for additional information.
/
(c)
Related to adoption of ASU 2018-02. See Note 1 for additional information.
Notes
to the Condensed Consolidated Financial Statements (Unaudited)
10. iLeases
The Company leases certain drilling rigs, facilities and other equipment.
As
discussed in Note 1, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease; (ii) lease classification; and (iii) initial direct costs. In addition, the Company elected the following practical expedients: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term
leases; and (iii) to combine and account for lease and nonlease contract components as a lease, which requires the capitalization of fixed nonlease payments on January 1, 2019 or lease effective date and the recognition of variable nonlease payments as variable lease expense.
On January 1, 2019, the Company recorded a total of $i89.0
million in right-of-use assets and corresponding new lease liabilities on its Condensed Consolidated Balance Sheet representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts
as of the lease effective date.
The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded on the balance sheet. As of June 30, 2019, the Company had no finance leases and was not a lessor.
i
The
following table summarizes operating lease costs for the three and six months ended June 30, 2019.
For
the three and six months ended June 30, 2019, total lease costs included $i20.8 million and $i39.4
million, respectively, capitalized to property, plant and equipment on the Condensed Consolidated Balance Sheet primarily for drilling rigs, of which $i16.0 million and $i32.7
million, respectively, related to operating lease costs. Variable lease costs also included short-term lease costs, which were immaterial.
For the six months endedJune 30, 2019, cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Company's Statement of Condensed Consolidated Cash Flows, was $i5.6
million. During the six months endedJune 30, 2019, the Company did not record any right-of-use assets in exchange for new lease liabilities.
The operating lease right-of-use assets were reported in other assets and the current and noncurrent portions of the operating lease liabilities were reported in other current liabilities and other liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of June 30, 2019, the operating right-of-use assets were $i51.6
million and operating lease liabilities were $i60.2 million, of which $i27.4 million was classified
as current. As of June 30, 2019, the weighted average remaining lease term was i3.6 years and the weighted average discount rate was i3.6%.
Notes to the Condensed Consolidated Financial Statements (Unaudited)
Schedule of Operating Lease Liability Maturities. iThe following table summarizes undiscounted cash flows owed by the
Company to lessors pursuant to contractual agreements in effect as of June 30, 2019.
In
2018, the Company sold its non-core Permian Basin assets located in Texas and its non-core assets in the Huron play (2018 Divestitures).
During the first quarter of 2018, the Company recorded an impairment of $i2.3 billion associated with certain non-core production and related
midstream assets in the Huron and Permian plays. The Company determined these properties and related pipeline assets were impaired as their carrying value exceeded the undiscounted cash flows which were expected to result from their continued use and potential disposition and because management no longer intended to develop the associated unproved properties. The first quarter of 2018 impairment reduced these assets to their estimated fair value of approximately $i1.0
billion.
The fair value of the impaired assets, as determined at March 31, 2018, was based on significant inputs that were not observable in the market and as such are considered to be Level 3 fair value measurements. See Note 5 for a description of the fair value hierarchy and Note 1 included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 for the policy on impairment of proved and unproved properties. Key assumptions included in the calculation of the fair value of the impaired assets as of March
31, 2018 included (i) reserves, including risk adjustments for probable and possible reserves; (ii) future commodity prices; (iii) to the extent available, market based indicators of fair value including estimated proceeds which could be realized upon a potential disposition; (iv) production rates based on the Company's experience with similar properties it operates; (v) estimated future operating and development costs; and (vi) a market-based weighted average cost of capital.
During the second quarter of 2018, the Company recorded an additional impairment/loss on sale of long-lived assets of $i118.1
million to write down the carrying value of the properties and related pipeline assets to the estimated amounts to be received upon the closing of the 2018 Divestitures. The Company received an initial deposit of $i57.5 million related to the sale of its non-core assets in the Huron play during the second quarter of 2018.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of financial condition and results of operations in conjunction with the Condensed Consolidated Financial Statements, and the notes thereto, included elsewhere in this report. For all periods prior
to the Separation and Distribution (as defined in Note 2 to the Condensed Consolidated Financial Statements), the results of operations of Equitrans Midstream Corporation (Equitrans Midstream) are reflected as discontinued operations. The Statements of Condensed Consolidated Operations have been recast to reflect this presentation and also included presenting certain transportation and processing expenses in continuing operations which were previously eliminated in consolidation. The cash flows related to Equitrans Midstream have not been segregated and are included within the Statements of Condensed Consolidated Cash Flows for all periods prior to the Separation and Distribution. See Note 2 to the Condensed Consolidated Financial Statements for amounts of the discontinued operations related to Equitrans Midstream which are included in the Statements of Condensed Consolidated Cash Flows.
CAUTIONARY
STATEMENTS
This Quarterly Report on Form 10-Q contains certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,”“estimate,”“could,”“would,”“will,”“may,”“forecast,”“approximate,”“expect,”“project,”“intend,”“plan,”“believe” and other words of similar meaning, or the negative thereof, in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report on Form 10-Q include the matters discussed
in the section captioned “Outlook” in Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of EQT Corporation and its subsidiaries (collectively, the Company), including guidance regarding the Company’s strategy to develop its Marcellus, Utica, Upper Devonian and other reserves; drilling plans and programs (including the number, type, depth, spacing, lateral lengths and location of wells to be drilled and the availability of capital to complete these plans and programs); production and sales volumes (including liquids volumes) and growth rates;
production of free cash flow and the Company's ability to reduce its drilling costs and capital expenditures; the Company's ability to maximize recoveries per acre; infrastructure programs; the cost, capacity, and timing of regulatory approvals; monetization transactions, including asset sales, joint ventures or other transactions involving the Company’s assets; acquisition transactions; the Company's ability to successfully implement and execute the new management team's strategic and operational plan and achieve the anticipated results of such plan; the Company’s
ability to achieve the anticipated synergies, operational efficiencies and returns from its acquisition of Rice Energy Inc.; the Company's ability to achieve the anticipated operational, financial and strategic benefits of its spin-off of Equitrans Midstream; the timing and structure of any dispositions of the Company's approximately 19.9% interest in Equitrans Midstream, and the planned use of the proceeds from any such dispositions; natural gas prices, changes in basis and the impact of commodity prices on the Company's business; reserves, including potential future downward adjustments and reserve life; potential future impairments of the Company's
assets; projected capital expenditures; the amount and timing of any repurchases of the Company's common stock; dividend amounts and rates; liquidity and financing requirements, including funding sources and availability; the Company's ability to maintain or improve its credit ratings; hedging strategy; the effects of litigation, government regulation, and tax position. The forward-looking statements included in this Quarterly Report on Form 10-Q involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements
on current expectations and assumptions about future events, taking into account all information currently available to the Company. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond the Company’s control. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors,” and elsewhere
in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, as updated by Part II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q, and the other documents the Company files from time to time with the Securities and Exchange Commission.
Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by law.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Consolidated Results of Operations
Income from continuing operations for the three months ended June 30, 2019 was $125.6 million, $0.49 per diluted share, compared
to a loss from continuing operations of $77.0 million, $0.29 per diluted share, for the three months ended June 30, 2018. The increase was primarily attributable to increased operating revenues driven by a gain on derivatives not designated as hedges in 2019 compared to a loss in 2018 and an impairment charge of $118.1 million recorded in the second quarter of 2018 associated with the 2018 Divestitures (as defined in Note 11 to the Condensed Consolidated Financial Statements). These improvements were partly offset by increased income tax expense and an unrealized
loss on the Company's investment in Equitrans Midstream.
Income from continuing operations for the six months endedJune 30, 2019 was $316.3 million, $1.24 per diluted share, compared to a loss from continuing operations of $1.7 billion, $6.25 per diluted share, for the six months endedJune 30, 2018. The increase was primarily attributable
to an impairment charge of $2.4 billion recorded in 2018 associated with the 2018 Divestitures andincreased operating revenues driven by an increase in gains on derivatives not designated as hedges, partly offset by increased income tax expense.
See “Sales Volumes and Revenues” and “Operating Expenses” for a discussion of items impacting operating income and “Other Income Statement Items” for a discussion of other income statement items. See “Investing Activities” under the caption “Capital Resources and Liquidity” for a discussion of capital expenditures.
Average Realized Price Reconciliation
The
following table presents detailed natural gas and liquids operational information to assist in the understanding of the Company’s consolidated operations, including the calculation of the Company's average realized price ($/Mcfe), which is based on adjusted operating revenues, a non-GAAP supplemental financial measure. Adjusted operating revenues is presented because it is an important measure used by the Company’s management to evaluate period-to-period comparisons of earnings trends. Adjusted operating revenues should not be considered as an alternative to total operating revenues. See “Reconciliation of Non-GAAP Financial Measures” for a reconciliation of adjusted operating revenues to total operating revenues.
Cash
settled basis swaps (not designated as hedges) ($/Mcf)
(0.05
)
(0.01
)
(0.08
)
(0.08
)
Average differential, including cash settled basis swaps ($/Mcf)
$
(0.41
)
$
(0.43
)
$
(0.28
)
$
(0.23
)
Average
adjusted price ($/Mcf)
$
2.35
$
2.55
$
2.76
$
2.85
Cash
settled derivatives (not designated as hedges) ($/Mcf)
0.20
0.09
0.07
0.07
Average natural gas price, including cash settled derivatives
($/Mcf)
$
2.55
$
2.64
$
2.83
$
2.92
Natural
gas sales, including cash settled derivatives
$
896,441
$
884,543
$
2,025,642
$
1,939,608
LIQUIDS
NGLs
(excluding ethane):
Sales volume (MMcfe) (c)
11,201
18,944
23,750
37,335
Sales
volume (Mbbls)
1,867
3,157
3,958
6,222
Price ($/Bbl)
$
21.15
$
36.39
$
25.75
$
36.94
Cash
settled derivatives (not designated as hedges) ($/Bbl)
2.86
(0.91
)
2.22
(1.06
)
Average NGLs price, including cash settled derivatives ($/Bbl)
$
24.01
$
35.48
$
27.97
$
35.88
NGLs
sales
$
44,821
$
112,034
$
110,724
$
223,270
Ethane:
Sales
volume (MMcfe) (c)
6,455
8,414
12,393
16,411
Sales volume (Mbbls)
1,076
1,402
2,066
2,735
Price
($/Bbl)
$
6.54
$
7.67
$
6.87
$
7.78
Ethane
sales
$
7,038
$
10,754
$
14,190
$
21,286
Oil:
Sales
volume (MMcfe) (c)
1,247
1,047
2,513
2,260
Sales volume (Mbbls)
208
175
419
377
Price
($/Bbl)
$
48.78
$
56.04
$
43.69
$
55.56
Oil
sales
$
10,140
$
9,784
$
18,300
$
20,930
Total
liquids sales volume (MMcfe) (c)
18,903
28,405
38,656
56,006
Total liquids sales volume (Mbbls)
3,151
4,734
6,443
9,334
Liquids
sales
$
61,999
$
132,572
$
143,214
$
265,486
TOTAL
PRODUCTION
Total natural gas & liquids sales, including cash settled derivatives (d)
$
958,440
$
1,017,115
$
2,168,856
$
2,205,094
Total
sales volume (MMcfe)
370,114
362,540
753,584
719,545
Average realized price ($/Mcfe)
$
2.59
$
2.81
$
2.88
$
3.06
(a)
The
Company’s volume weighted New York Mercantile Exchange (NYMEX) natural gas price (actual average NYMEX natural gas price ($/MMBtu)) was $2.64 and $2.80 for the three months ended June 30, 2019 and 2018, respectively, and $2.89 and $2.90 for the six months ended June 30, 2019 and 2018, respectively.
(b)
Basis
represents the difference between the ultimate sales price for natural gas and the NYMEX natural gas price.
(c)
NGLs, ethane and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
(d)
Also referred to in this report as adjusted operating revenues, a non-GAAP supplemental financial measure.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Reconciliation of Non-GAAP Financial Measures
The table below reconciles adjusted operating revenues, a non-GAAP supplemental financial measure, to total operating revenues, its most directly comparable financial measure calculated in accordance with GAAP. Adjusted operating revenues (also referred to as total natural gas & liquids sales, including cash settled derivatives) is presented because it is an important measure used by the
Company’s management to evaluate period-over-period comparisons of earnings trends. Adjusted operating revenues as presented excludes the revenue impact of changes in the fair value of derivative instruments prior to settlement and the revenue impact of "net marketing services and other." Management utilizes adjusted operating revenues to evaluate earnings trends because the measure reflects only the impact of settled derivative contracts and thus does not impact the revenue from natural gas sales with the often volatile fluctuations in the fair value of derivatives prior to settlement. Adjusted operating revenues also excludes "net marketing services and other" because management considers these revenues to be unrelated to the revenues for its natural gas and liquids production. "Net marketing services and other" primarily includes the cost of and recoveries
on pipeline capacity releases and revenues for gathering services. Management further believes that adjusted operating revenues as presented provides useful information to investors for evaluating period-over-period earnings trends.
Gain
(loss) on derivatives not designated as hedges
407,635
(53,897
)
(856.3
)
275,639
8,695
3,070.1
Net
marketing services and other
2,090
13,180
(84.1
)
5,646
36,250
(84.4
)
Total
operating revenues
$
1,310,252
$
950,648
37.8
$
2,453,425
$
2,262,684
8.4
(a)
Includes
Upper Devonian wells.
(b)
NGLs, ethane and crude oil were converted to Mcfe at the rate of six Mcfe per barrel for all periods.
Total operating revenues were $1,310.3 million for the three months ended June 30, 2019 compared to $950.6 million for the three months ended June 30, 2018. Sales of natural gas, oil and NGLs decreased as a result of a lower average
realized price, the 2018 Divestitures and the normal production decline in the Company’s producing wells, partly offset by a 2% increase in sales volumes in 2019 as a result of increased production from the 2017 and 2018 drilling programs. Excluding sales volumes related to the 2018 Divestitures, sales volumes of natural gas, oil and NGLs increased 8% in the second quarter of 2019. For the three months ended
Management’s Discussion and Analysis of Financial Condition and Results of Operations
June 30, 2019 compared to the three months ended June 30, 2018, the average realized price decreased due to lower NYMEX and lower liquids sales and Btu uplift as a result of the 2018 Divestitures, partly offset by higher average differential and cash settled derivatives. The Company received $53.1 million
and $25.5 million of net cash settlements for derivatives not designated as hedges for the three months ended June 30, 2019 and 2018, respectively, that are included in the average realized price but may not be included in the GAAP operating revenues during the period.
Changes in fair market value of derivative instruments prior to settlement are recognized in gain (loss) on derivatives not designated as hedges. Total operating revenues for the three months ended June 30, 2019 included a $407.6 million
gain on derivatives not designated as hedges compared to $53.9 million loss on derivatives not designated as hedges for the three months ended June 30, 2018. The gain for the three months ended June 30, 2019 primarily related to increases in the fair market value of the Company’s NYMEX swaps and options due to decreases in NYMEX prices during the quarter.
Net marketing services and other decreased for the three months ended June 30, 2019 compared to the three
months ended June 30, 2018 as a result of fewer capacity releases and lower capacity release rates related to the Company’s Tennessee Gas Pipeline capacity in addition to lower revenues from gathering services as result of the 2018 Divestitures.
Total operating revenues were $2.5 billion for the six months ended June 30, 2019 compared to $2.3 billion for the six months ended June 30, 2018. Sales of natural gas, oil and NGLs decreased as a result
of a lower average realized price, the 2018 Divestitures and the normal production decline in the Company’s producing wells, partly offset by a 5% increase in sales volumes in 2019 as a result of increased production from the 2017 and 2018 drilling programs. Excluding sales volumes related to the 2018 Divestitures, sales volumes of natural gas, oil and NGLs increased 10% in 2019. For the six months ended June 30, 2019 compared to the six months ended June
30, 2018, the average realized price decreased due to lower liquids sales and Btu uplift as a result of the 2018 Divestitures and lower average differential. The Company paid $10.5 million and $13.1 million of net cash settlements for derivatives not designated as hedges for the six months ended June 30, 2019 and 2018, respectively, that are included in the average realized price but may not be included in the GAAP operating revenues during the period.
Total operating revenues for the six
months ended June 30, 2019 compared to the six months ended June 30, 2018 increased due to higher gains on derivatives not designated as hedges. The gain for the six months ended June 30, 2019 primarily related to increases in the fair market value of the Company’s NYMEX swaps and options due to decreases in NYMEX prices during the year, partly offset by decreases in the fair market value of the Company's basis swaps due to increases in basis prices during the year.
Net
marketing services and other decreased for the six months ended June 30, 2019 as a result of fewer capacity releases and lower capacity release rates related to the Company’s Tennessee Gas Pipeline capacity in addition to lower revenues from gathering services as result of the 2018 Divestitures.
Lease
operating expenses (LOE), excluding production taxes
0.05
0.08
(37.5
)
0.05
0.09
(44.4
)
Production
taxes
0.05
0.06
(16.7
)
0.05
0.06
(16.7
)
Exploration
0.01
—
100.0
—
—
—
Selling,
general and administrative
0.23
0.17
35.3
0.18
0.14
28.6
Production
depletion
$
1.00
$
1.00
—
$
1.00
$
1.03
(2.9
)
Operating
expenses:
Gathering
$
204,127
$
194,751
4.8
$
418,728
$
388,369
7.8
Transmission
200,122
187,158
6.9
392,428
365,174
7.5
Processing
32,735
46,160
(29.1
)
65,074
91,183
(28.6
)
LOE,
excluding production taxes
17,155
27,457
(37.5
)
40,227
61,589
(34.7
)
Production
taxes
19,161
20,406
(6.1
)
39,497
44,908
(12.0
)
Exploration
1,857
1,653
12.3
2,864
2,878
(0.5
)
Selling,
general and administrative
$
86,208
$
62,959
36.9
$
135,186
$
102,774
31.5
Depreciation
and depletion:
Production depletion
$
368,734
$
362,819
1.6
$
756,148
$
743,344
1.7
Other
depreciation and depletion
3,679
8,890
(58.6
)
7,378
21,058
(65.0
)
Total
depreciation and depletion
$
372,413
$
371,709
0.2
$
763,526
$
764,402
(0.1
)
Gathering
expense increased on an absolute basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018primarilydue to the increase in sales volumes. Gathering expense on a per Mcfe basis was impacted by the 2018 Divestitures. Excluding the sales volumes related to the 2018 Divestitures, gathering expense on a per Mcfe basis was $0.57 for the three and six
months ended June 30, 2018.
Transmission expense increased on an absolute basis and on a per Mcfe basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 due to increased transportation capacity to move the Company’s
natural gas out of the Appalachian Basin, increased volumetric charges and costs associated with additional unreleased Tennessee Gas Pipeline capacity. These increases were partly offset by reduced firm capacity costs as a result of the 2018 Divestitures.
Processing expense decreased on an absolute basis and on a per Mcfe basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018
primarily as a result of the decrease in NGL sales volumes associated with the 2018 Divestitures.
LOE decreased on an absolute basis and on a per Mcfe basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily as a result of the 2018 Divestitures and increased sales volumes in 2019.
Production
taxes decreased on an absolute basis and on a per Mcfe basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily as a result of the 2018 Divestitures.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Selling, general and administrative expense increased on an absolute basis and on a per Mcfe basis for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 primarily due to a $37.8 million increase in royalty and litigation reserves, net of settlements received, during the second quarter of 2019. This increase was partly offset by a decrease in long-term incentive compensation due to changes in
the fair value of awards. Selling, general and administrative expense increased on an absolute basis and on a per Mcfe basis for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 primarily due to a $45.8 million increase in royalty and litigation reserves, net of settlements, received during the first six months of 2019. This increase was partly offset by a decrease in long-term incentive compensation due to changes in the fair value of awards and decreased labor and personnel costs as a result of the Company's efficiency efforts. Long-term incentive compensation may fluctuate with changes in the
Company's stock price and performance conditions.
Production depletion increased during the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and the six months ended June 30, 2019 compared to the six months ended June 30, 2018 as a result of higher produced volumes partly offset by a lower depletion rate. Other depreciation and depletion decreased as a result of the 2018 Divestitures.
See
Note 11 to the Condensed Consolidated Financial Statements for a discussion of impairment/loss on sale of long-lived assets in 2018.
Lease impairments and expirations increased for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and for the six months ended June 30, 2019 compared to the six months ended June 30, 2018 due to an increase in lease expirations. The increase in the number of leases expiring in 2019 is primarily
due to acquisition activity completed by the Company in 2016 and 2017.
Proxy, transaction and reorganization increased during the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and during the six months ended June 30, 2019 compared to the six months ended June 30, 2018. Costs in 2019 are primarily related to proxy fees and costs in 2018 are primarily related to
legal and banking fees due to the acquisition of Rice Energy Inc.
Other Income Statement Items
The Company's investment in Equitrans Midstream is recorded at fair value based on the closing stock price of Equitrans Midstream multiplied by the number of shares of common stock owned by the Company. The changes in fair value are recorded in the Statements of Condensed Consolidated Operations as an unrealized gain (loss) on investment in Equitrans Midstream.
Dividend
and other income (expense) increased primarily due to dividends received from Equitrans Midstream of $22.8 million and $43.5 million during the three and six months ended June 30, 2019, respectively.
Interest expense decreased by $6.6 million for the three months ended June 30, 2019 compared to the three months ended June 30, 2018 and $8.0 million for the six months ended June
30, 2019 compared to the six months ended June 30, 2018 primarily as a result of decreased borrowings under the Company's credit facility and the repayment of the $700 million in aggregate principal amount of 8.125% Senior Notes which matured on June 1, 2019. These decreases were partly offset by interest incurred on borrowings under the Term Loan Facility (as defined in Note 7 to the Condensed Consolidated Financial Statements) and an increased interest rate on the Company's variable rate long-term
debt.
See discussion of income tax expense (benefit) in Note 6 to the Condensed Consolidated Financial Statements.
OUTLOOK
As a result of the change in control events described in Item 5, “Other Information,”the Company has embarked on a plan to transform the Company into a modern, digitally-enabled exploration and production company. This plan includes a
variety of operational, management and other changes to the business in order to increase efficiency, improve well performance and increase technology use, all while maintaining focus on being the lowest cost producer in the Appalachian Basin. The Company intends to reposition the organization to effectively execute on large-scale combo development projects, which consist of developing multiple wells and pads simultaneously, and intends to take a disciplined approach to capital allocation and in establishing its development schedule. The level of future development capital spending will be determined by the economics of the Company’s available projects in light of the commodity price environment. Future production growth will be an output of that economic decision. As a result, the
Company has suspended its outlook for 2020 and beyond pending the completion of the revised plan, which is expected to be available in the next 60 to 90 days.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
For 2019, the Company reaffirms guidance for capital expenditures
of $1.825 billion to $1.925 billion, which are expected to be funded by operating cash flow and, if required, borrowings under the Company's credit facility. Sales volumes are expected to be 1,480 to 1,520 Bcfe for 2019. The Company will continue to assess the current commodity price environment as well as its development plan and may decrease 2019 capital expenditures accordingly.
Additionally, as a result of the change in control described in Item 5, "Other Information,"the Company may (i) impair certain intangible assets associated with non-compete agreements for former Rice Energy executives who are now employees of the
Company and (ii) incur other charges, including those associated with severance or incentive compensation plan changes.
The Company’s revenues, earnings, liquidity and ability to grow are substantially dependent on the prices it receives for, and the Company’s ability to develop its reserves of, natural gas, oil and NGLs. Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas, oil and NGLs at the Company's ultimate sales points and thus cannot predict the ultimate
impact of prices on its operations. Changes in natural gas, oil and NGLs prices could affect, among other things, the Company's development plans, which would increase or decrease the pace of the development and the level of the Company's reserves, as well as the Company's revenues, earnings or liquidity. Lower prices could also result in non-cash impairments in the book value of the Company’s oil and gas properties or other long lived intangible assets or downward adjustments to the Company’s estimated proved reserves. Any such impairment and/or downward adjustment
to the Company’s estimated reserves could potentially be material to the Company.
See "Critical Accounting Policies and Estimates" and Note 1 to the Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of the Company’s accounting policies and significant assumptions related to accounting for oil and gas producing activities, and the
Company's policies and processes with respect to impairment reviews for proved and unproved property. See also Item 1A, "Risk Factors - Natural gas, NGLs and oil price declines have resulted in impairment of certain of our non-core assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, including long lived intangible assets, which could materially and adversely affect our results of operations in future periods" in the Company's Annual Report on Form 10-K for the year ended December 31, 2018.
CAPITAL
RESOURCES AND LIQUIDITY
Operating Activities. Net cash flows provided by operating activities totaled $1,314.8 million for the six months ended June 30, 2019 compared to $1,541.1 million for the six months ended June 30, 2018. The decrease was driven by the results of discontinued operations included in the six months ended June 30, 2018 and lower
cash operating revenues in excess of cash expenses, partly offset by the favorable timing of working capital payments between the two periods and dividends received from Equitrans Midstream of $43.5 million.
The Company's cash flows from operating activities will be impacted by future movements in the market price for commodities. The Company is unable to predict these future price movements outside of the current market view as reflected in forward strip pricing. Refer to Item 1A, "Risk Factors - Natural gas, NGLs and oil price volatility, or a prolonged period of low natural gas, NGLs and oil prices, may have an adverse effect upon our revenue, profitability, future rate of growth, liquidity and financial position"
in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for further information.
Investing Activities. Net cash flows used in investing activities totaled $764.6 million for the six months ended June 30, 2019 compared to $1,762.2 million for the six months ended June 30, 2018. The decrease
was primarily due to lower capital expenditures during the six months ended June 30, 2019 as a result of the change in strategy from production growth to capital efficiency as well as capital expenditures and capital contributions associated with the midstream business included in the six months ended June 30, 2018. During the first six months of 2019, the Company spud 64 gross wells (56 net), including 48
Marcellus gross wells (45 net) in Pennsylvania, 6 Marcellus wells in West Virginia and 10 Ohio Utica gross wells (5 net). During the first six months of 2018, the Company spud 90 gross wells (77 net), including 64 Marcellus wells (63 net) in Pennsylvania and 26 Ohio Utica gross wells (14 net).
Total
capital expenditures from continuing operations
466
716
942
1,326
Midstream infrastructure (a)
—
212
—
383
Total
capital expenditures
466
928
942
1,709
Add (deduct) non-cash items (b)
(71
)
36
(176
)
(16
)
Total
cash capital expenditures
$
395
$
964
$
766
$
1,693
(a)
Capital
expenditures related to midstream infrastructure are presented as discontinued operations as described in Note 2 to the Condensed Consolidated Financial Statements.
(b)
Represents the net impact of non-cash capital expenditures including capitalized share-based compensation costs as well as the impact of timing of receivables from working interest partners and accrued capital expenditures.
Financing Activities. Net cash flows used in financing activities totaled $523.5 million
for the six months ended June 30, 2019 compared to net cash flows provided by financing activities of $771.8 million for the six months ended June 30, 2018. For the six months ended June 30, 2019, the primary uses of financing cash flows were net repayments of credit facility borrowings and debt while the primary source of financing cash flows was net proceeds from borrowings under the Term Loan Facility. For the six months endedJune 30, 2018, the primary source of financing cash flows was net proceeds from a senior notes offering by EQM Midstream Partners, LP (EQM) while the primary uses of financing cash flows were a net decrease in EQT, EQM and Rice Midstream Partners LP credit facility borrowings, distributions to noncontrolling interests, EQM's acquisition of the remaining 25% ownership interest in Strike Force Midstream LLC, repurchase and retirement of common stock and cash paid for taxes on share-based incentive awards.
The Company may from time to time seek to repurchase its outstanding debt securities. Such repurchases, if any, will depend on prevailing market conditions, the
Company's liquidity requirements, contractual and legal restrictions and other factors. In addition, the Company plans to dispose of its retained shares of Equitrans Midstream’s common stock and use the proceeds to reduce the Company's debt.
Security Ratings and Financing Triggers
The table below reflects the credit ratings and ratings outlook assigned to debt instruments of the Company as of July 25, 2019. Changes in credit ratings may affect
the Company’s cost of short-term debt through interest rates and fees under its lines of credit. Changes in credit ratings or ratings outlook may also affect collateral requirements under the Company’s derivative instruments and midstream services contracts, rates available on new long-term debt, and access to the credit markets.
Rating Service
Credit
Rating
Outlook
Moody’s
Baa3
Negative
S&P
BBB-
Stable
Fitch Ratings Service (Fitch)
BBB-
Stable
The
Company’s credit ratings and ratings outlook are subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn by a credit rating agency if, in its judgment, circumstances so warrant. If any credit rating agency downgrades the Company’s rating, particularly below investment grade, or institutes a "negative" rating outlook, the Company’s access to the capital markets may be limited, borrowing costs and
Management’s Discussion and Analysis of Financial Condition and Results of Operations
margin deposits on the Company’s derivative instruments may increase, the Company's counterparties under midstream services contracts may request additional assurances, including collateral, and the Company’s potential pool of investors and funding sources may decrease.
The required margin on the Company’s derivative instruments is also subject to significant change as a result of factors other than credit rating, such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company. As of July 25, 2019, the Company had sufficient unused borrowing capacity under its credit facility to satisfy any requests for margin or other collateral that a counterparty would be permitted to request of the Company under its derivative contracts
and midstream services contracts in the event that the Company’s credit rating were to fall one rating category. See Note 4 to the Condensed Consolidated Financial Statements for further discussion on what is deemed investment grade and a discussion of other factors affecting margin deposit requirements.
The Company’s debt agreements and other financial obligations contain various provisions that, if not complied with, could result in termination of the agreements, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default
under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s credit facility and the Term Loan Agreement each contain financial covenants that require the Company to have a total debt-to-total capitalization ratio no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income (OCI). As of June 30, 2019, the Company was in compliance with all debt
provisions and covenants.
See Note 7 to the Condensed Consolidated Financial Statements for a discussion of the borrowings under the Company's credit facility and Term Loan Facility.
Commodity Risk Management
The substantial majority of the Company’s commodity risk management program is related to hedging sales of the Company’s produced natural gas. The
Company’s overall objective in this hedging program is to protect cash flow from undue exposure to the risk of changing commodity prices. The derivative commodity instruments currently utilized by the Company are primarily swaps, calls and puts. As of July 22, 2019, the approximate volumes and prices of the Company’s NYMEX hedge positions through 2023 are:
2019
(a)
2020
2021
2022
2023
Swaps
Volume
(MMDth)
441
580
314
138
70
Average
Price($/Dth)
$
2.85
$
2.81
$
2.78
$
2.75
$
2.73
Calls
- Net Short
Volume (MMDth)
197
248
58
22
7
Average
Short Strike Price ($/Dth)
$
3.02
$
3.07
$
3.14
$
3.20
$
3.18
Puts
- Net Long
Volume (MMDth)
4
10
10
—
—
Average
Long Strike Price ($/Dth)
$
2.60
$
2.25
$
2.71
$
—
$
—
Fixed
Price Sales (b)
Volume (MMDth)
47
14
4
—
—
Average
Price ($/Dth)
$
2.82
$
2.79
$
2.72
$
—
$
—
(a)
July
1 through December 31.
(b)
The difference between the fixed price and NYMEX is included in average differential on the Company’s price reconciliation under "Consolidated Results of Operations." The fixed price natural gas sales agreements can be physically or financially settled.
For 2019 (July - December), 2020, 2021, 2022
and 2023, the Company has natural gas sales agreements for approximately 17 MMDth, 13 MMDth, 18 MMDth, 18 MMDth and 18 MMDth, respectively, that include average NYMEX ceiling prices of $3.37, $3.68, $3.17, $3.17 and $3.17, respectively. Currently, the Company has also entered into derivative instruments to hedge
basis and a limited number of contracts to hedge its NGLs exposure. The Company may also use other contractual agreements in implementing its commodity hedging strategy.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
See
Item 3, "Quantitative and Qualitative Disclosures About Market Risk," and Note 4 to the Company’s Condensed Consolidated Financial Statements for further discussion of the Company’s hedging program.
Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the
Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the Company’s financial condition, results of operations
or liquidity. See Note 15 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of the Company's commitments and contingencies. See also Part II, Item 1 "Legal Proceedings" in this Quarterly Report on Form 10-Q.
Off-Balance Sheet Arrangements
See Note 16 to the Consolidated Financial Statements in the Company's Annual Report on Form 10-K for the year ended
December 31, 2018 for a discussion of the Company's guarantees.
Dividend
On July 10, 2019, the Board of Directors of the Company declared a regular quarterly cash dividend of $0.03 per share, payable September 1, 2019, to the Company’s shareholders of record at
the close of business on August 9, 2019.
Critical Accounting Policies
The Company’s significant accounting policies are described in Item 7, "Management’s Discussion and Analysis of Financial Condition and Results of Operations," contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements
have been included in the notes to the Company’s Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk and Derivative Instruments
The Company's primary market risk exposure is the volatility of future prices for natural gas and NGLs. Due to the volatility of commodity prices, the Company is unable to predict future potential movements in the market prices for natural gas and NGLs at the
Company's ultimate sales points and thus cannot predict the ultimate impact of prices on its operations. Prolonged low, and/or significant or extended declines in, natural gas and NGLs prices could adversely affect, among other things, the Company’s development plans, which would decrease the pace of development and the level of the Company's proved reserves.
The Company uses derivatives to reduce the effect of commodity price volatility. The Company's use of derivatives is further described in Note 4
to the Condensed Consolidated Financial Statements and under the caption "Commodity Risk Management" in the "Capital Resources and Liquidity" section of Item 2, "Management’s Discussion and Analysis of Financial Condition and Results of Operations."The Company's over the counter (OTC) derivative commodity instruments are placed primarily with financial institutions and the creditworthiness of these institutions is regularly monitored. The Company primarily enters into derivative instruments to hedge forecasted sales of production. The Company also enters into derivative instruments to hedge basis and exposure to fluctuations in interest rates. The
Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee and reviewed by the Audit Committee of the Company’s Board of Directors.
For the derivative commodity instruments used to hedge the Company’s forecasted sales of production, most of which are hedged at NYMEX natural gas prices, the Company sets policy limits relative to the expected production and sales levels which are exposed to price risk. The
Company has an insignificant amount of financial natural gas derivative commodity instruments for trading purposes.
The derivative commodity instruments currently utilized by the Company are primarily fixed price swap agreements, collar agreements and option agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company may also use other contractual agreements in implementing its commodity hedging strategy.
The Company monitors price and
production levels on a continuous basis and makes adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to protect a portion of cash flows from undue exposure to the risk of changing commodity prices.
For information on the quantity of derivative commodity instruments held by the Company, see Note 4 to the Condensed Consolidated Financial Statements and the "Commodity Risk Management" section in the "Capital Resources and Liquidity" section of Item 2, "Management’s Discussion and Analysis of Financial Condition and Results of Operations."
A
hypothetical decrease of 10% in the market price of natural gas from the June 30, 2019 and December 31, 2018 levels would have increased the fair value of these natural gas derivative instruments by approximately $382.5 million and $432.5 million, respectively. A hypothetical increase of 10% in the market price of natural gas from the June 30, 2019 and December 31, 2018 levels would have decreased the fair value of these natural gas derivative instruments by approximately $396.1
million and $443.4 million, respectively. The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal determination of fair value as described in Note 5 to the Condensed Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at June 30, 2019 and December 31, 2018. The price change was then applied to these natural gas derivative commodity instruments recorded on the
Company’s Condensed Consolidated Balance Sheets, resulting in the hypothetical change in fair value.
The above analysis of the derivative commodity instruments held by the Company does not include the offsetting impact that the same hypothetical price movement may have on the Company’s physical sales of natural gas. The portfolio of derivative commodity instruments held to hedge the Company’s forecasted produced gas approximates a portion of the Company’s expected physical sales of natural gas. Therefore, an adverse impact to the fair value of
the portfolio of derivative commodity instruments held to hedge the Company’s forecasted production associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on the Company’s physical sales of natural gas, assuming the derivative commodity instruments are not closed out in advance of their expected term, and the derivative commodity instruments continue to function effectively as hedges of the underlying risk.
If
the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Interest Rate Risk
Changes in interest rates affect the amount of interest the Company earns on cash, cash equivalents and short-term investments and the interest rates the Company pays on borrowings under its credit facility, Term Loan Facility and floating rate notes. All of the
Company’s Senior Notes, other than the Company's floating rate notes, are fixed rate and thus do not expose the Company to fluctuations in its results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of the Company’s fixed rate debt. See Note 7 to the Condensed Consolidated Financial Statements for further discussion of the Company’s credit facility and Term Loan Facility borrowings and Note 5 to the Condensed Consolidated Financial Statements for a discussion of fair value measurements,
including the fair value of long-term debt.
Other Market Risks
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company’s OTC derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies
individually as well as the financial industry as a whole. The Company utilizes various processes and analyses to monitor and evaluate its credit risk exposures. These include closely monitoring current market conditions, counterparty credit fundamentals and credit default swap rates. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
As of June 30,
2019, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The
Company monitors market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheets.
The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas, NGLs and oil. A significant amount of revenues and related accounts receivable are generated from the sale of produced natural gas and NGLs to certain marketers, utility and industrial customers located in the Appalachian Basin and in markets available through the Company's current transportation portfolio, which includes markets in the Gulf Coast, Midwest and Northeast
United States and Canada. The Company also contracts with certain processors to market a portion of NGLs on behalf of the Company.
No one lender of the large group of financial institutions in the syndicate for the Company's credit facility and the Term Loan Facility holds more than 10% and 15%, respectively. The large syndicate group and relatively low percentage of participation by each lender are expected to limit the Company’s exposure to disruption or consolidation
in the banking industry.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)),
was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There
were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the second quarter of 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In
the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the
Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial condition, results of operations or liquidity of the Company.
Environmental Proceedings
Well Monitoring under Consent Order, Washington County, Pennsylvania. On November 17, 2016, Rice Drilling B, LLC (Rice Drilling B), which the Company acquired in connection with the acquisition of Rice Energy Inc. in November 2017, entered
into a Consent Order and Agreement (the Agreement) with the Pennsylvania Department of Environmental Protection (PADEP) to address, among other things, Rice Drilling B’s failure to set the required length of coal protective casing in a well. Under the terms of the Agreement, Rice Drilling B agreed to conduct monthly tests on the well casing and report the test results on a quarterly basis to the PADEP for a 2-year period. The Agreement included negotiated stipulated penalties that automatically applied if Rice Drilling B failed to comply with the Agreement. Rice Drilling B failed to comply with the Agreement requirements but did not pay the stipulated penalties to the PADEP as set forth under the Agreement. Upon the Company’s acquisition of Rice Drilling B, Rice Drilling B began conducting the monthly casing tests required under the Agreement, but neglected to provide the PADEP with the
results of the tests in its quarterly reports to the PADEP. On May 14, 2019, the PADEP sent a letter to the Company requesting payment of the stipulated penalties for the time period that Rice Drilling B failed to comply with the Agreement. The Company met with the PADEP to discuss the Agreement and the PADEP agreed that stipulated penalties would only be due beginning from the date the Company acquired Rice Drilling B. In June 2019, the Company paid the stipulated penalties to the PADEP in the amount of $144,300 and the matter is now closed. The payment did not have a material impact on the
financial condition, results of operations, or liquidity of the Company.
Well Control Event at Habanaro Well, Washington County, Pennsylvania. On October 12, 2018, the Company received a Notice of Violation (NOV) from the PADEP relating to a well control event that occurred on September 26, 2018, at the Company’s Habanaro well pad in Washington County, Pennsylvania. The NOV alleged multiple violations of the Oil and Gas Act and the Clean Streams Law pertaining to the well control event. The
Company took immediate actions to bring the well into control and cooperated fully with the PADEP in its investigation of the event. In June 2019, the PADEP offered to settle the Company’s civil penalty liability related to the incident. The Company and the PADEP are currently negotiating a civil penalty settlement for this matter. While the Company anticipates that any settlement with the PADEP for this matter will result in a payment that exceeds $100,000, the Company expects that the resolution of this matter will not have a material impact on the financial condition, results of operations or liquidity of the
Company.
Other Legal Proceedings
Kay Company, LLC, et al. v. EQT Production Company, et al., United States District Court for the Northern District of West Virginia. On January 16, 2013, several royalty owners who had entered into leases with EQT Production Company, a subsidiary of the Company, filed a gas royalty class action lawsuit in the Circuit Court of Doddridge County, West Virginia. The suit alleged that EQT Production Company and a number of related companies, including the Company, EQT Energy, LLC, EQT Investments Holdings, LLC, EQM
Midstream Partners, LP (the Company’s former midstream affiliate) and Equitrans Gathering Holdings, LLC (formerly known as EQT Gathering Holdings, LLC, and a former subsidiary of the Company), failed to pay royalties on the fair value of the gas produced from the leases and took improper post-production deductions from the royalties paid. The plaintiffs sought more than $100 million (according to expert reports) in compensatory damages, punitive damages, and other relief. On May 31, 2013, the defendants removed the lawsuit to federal court. On September 6, 2017, the district court granted the plaintiffs’ motion to certify the class and granted the plaintiffs’ motion for summary judgment, finding that EQT Production
Company and
its marketing affiliate EQT Energy, LLC are alter egos of one another. The defendants sought immediate appeal of the class certification. On November 30, 2017, the Court of Appeals declined the request for an immediate review. On February 13, 2019, the Company announced that it and the other defendants reached a tentative settlement agreement with the class
representatives. Pursuant to the terms of the proposed settlement agreement, the Company agreed to pay $53.5 million into a settlement fund established to disburse payments to class participants (the Qualified Settlement Fund), and stop taking future post production deductions on leases that are determined by the Court to not permit deductions. The Company and the class representatives also agreed that future royalty payments will be based on a clearly defined index pricing methodology. The tentative settlement agreement was subject to Court approval and achieving a threshold minimum percentage of participation by the class members. The Court preliminarily approved the settlement on February 13, 2019. Each class member had until May
17, 2019 to elect to opt-out of the settlement. Less than 1% of the class members elected to opt-out of the settlement. The final approval hearing was held on June 24, 2019 and the Court orally granted final approval of the settlement. All money owed by the Company under the settlement agreement was paid by the Company into the Qualified Settlement Fund on July 8, 2019. A final Order approving the settlement was issued on July 22, 2019, and all royalty claims (other than those that elected to opt-out of the settlement or that are excluded as part of the settlement agreement) for the class period, which spans from 2009 through 2017, have been resolved.
Mary
Farr Secrist, et al. v. EQT Production Company, et al., Circuit Court of Doddridge County, West Virginia. On May 2, 2014, royalty owners whose predecessors had entered into a 960-acre lease (the Stout Lease) and several additional leases comprising 6,356-acres (the Cities Services Lease) with EQT Production Company’s predecessor, each covering acreage in Doddridge County, West Virginia, filed a complaint in the Circuit Court of Doddridge County, West Virginia. The complaint alleged that EQT Production Company and a number of related companies, including the Company, EQT Gathering, LLC, EQT Energy, LLC, and EQM Midstream Services, LLC (formerly known as EQT Midstream Services, LLC, the general partner of the Company’s former midstream
affiliate), underpaid on royalties for gas produced under the leases and took improper post-production deductions from the royalties paid. With respect to the Stout Lease, the plaintiffs also asserted that the Company committed a trespass by drilling on the leased property, claiming that the Company had no right under the lease to drill in the Marcellus shale formation. The plaintiffs sought more than $100 million in compensatory damages for the trespass claim under the Stout Lease, and approximately $20 million for insufficient royalties under both the Stout Lease and the Cities Services Lease, in addition to punitive damages and other relief. On June 27, 2018, the Court held that EQT Production Company and its marketing affiliate EQT Energy, LLC are alter
egos of one another and that royalties paid under the leases should have been based on the price of gas produced under the leases when sold to unaffiliated third parties, and not on the price when the gas was sold from EQT Production Company to EQT Energy, LLC. Further, on January 14, 2019, the Court entered an Order granting the plaintiffs’ motion for summary judgment and declaring that the Company did not have the right to drill in the Marcellus shale formation under the Stout Lease. The Court also ruled that seven of the Company’s wells that have been producing gas under the Stout Lease are trespassing, and that a jury will determine whether the trespass was willful or innocent. On February 27, 2019, the
Company filed a motion seeking permission to immediately appeal the trespass Order to the West Virginia Supreme Court; however, the motion was denied on March 25, 2019, and the Court continued the trial to September 2019. On May 28, 2019, the Court entered an Order excluding certain of the Company’s costs that could have otherwise offset any damages for innocent trespass under the Stout Lease. Trial is scheduled for September 3, 2019.
Item 1A. Risk Factors
There
have been no material changes from the risk factors previously disclosed in Item 1A, “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2018, other than those listed in this section.
We are under the leadership of a substantially reconstituted Board of Directors and a new Chief Executive Officer who plan to implement a variety of operational, organizational, cultural and other changes to our business, and we may not be able to achieve some or all of the anticipated benefits of this transformation plan.
Our Board of Directors was substantially reconstituted at
our annual meeting of shareholders on July 10, 2019 and, following that meeting, Toby Z. Rice was appointed as President and Chief Executive Officer. Prior to our annual meeting, the proponents of our reconstituted Board of Directors disclosed a detailed transformation plan designed to effect operational, organizational, cultural and other changes to our business in order to lower operating costs and increase free cash flow generation through improved efficiency, well performance and the use of technology. As a result of these events, during the third quarter of 2019, we expect to record severance payments and other compensation expense associated with the departure of certain of our officers and other employees, and we may incur other similar types of expenses and charges during the third quarter and thereafter related to other employee departures or otherwise associated with implementation of the transformation plan.
In addition, while we believe that the successful implementation of the transformation plan will improve our operational and financial performance, there can be no assurance that we will be able to successfully implement the transformation plan or otherwise realize the anticipated benefits of
the transformation plan and we may encounter short-term disruptions of certain aspects of our business as elements of the transformation plan are implemented.
Item
2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred during the three months ended June 30, 2019:
Period
Total
number of shares purchased (a)
Average price
paid per share
Total number of shares purchased as part of publicly announced plans
or programs
Approximate dollar value of shares that may yet be purchased under plans or programs
Reflects
the number of shares withheld by the Company to pay taxes upon vesting of restricted stock.
Item 5. Other Information
Departure of Directors and Certain Officers; Election of Directors and Appointment of Certain Officers; 2019 Annual Meeting of Shareholders
On July 10, 2019, at the Company's 2019 annual meeting of shareholders (the Annual Meeting),
shareholders of the Company elected 12 individuals to the Company’s Board of Directors (the Board). In total, there were 18 director nominees - seven of whom were nominated by Toby Z. Rice and other participants named in the definitive proxy statement filed on May 20, 2019 (the Rice Group), including Daniel J. Rice IV, who was nominated by both the Board and the Rice Group; and five of whom were nominated by the Board and recommended by the Rice Group. At the Annual Meeting, the Company’s shareholders elected all 12 candidates recommended by the Rice Group to the Board to serve for one-year terms expiring at the
Company’s 2020 annual meeting of shareholders. Following election and appointment, the Board terminated the employment of Robert J. McNally as President and Chief Executive Officer and Jonathan M. Lushko as General Counsel and Senior Vice President, Government Affairs, and appointed Toby Z. Rice as President and Chief Executive Officer and William E. Jordan as Executive Vice President and General Counsel, in each case effective as of July 10, 2019.
Former Employee Litigation
In February 2019, the Company filed a claim (EQT Corporation v. Lo) alleging theft and misappropriation of trade secrets and other
confidential and proprietary information against a former EQT employee. In June 2019, the Company issued subpoenas for document production against Toby Z. Rice and certain of his affiliates as witnesses related to such matter. Outside counsel for Mr. Rice objected to the subpoenas. At its regular meeting on July 10, 2019, the Board appointed a special committee of independent directors with no prior affiliation to the Company or Rice Energy Inc. to oversee the matter on behalf of the Company. William E. Jordan, newly appointed Executive Vice President and General Counsel of the Company, recused
himself from any involvement in the matter due to his prior affiliation with Mr. Rice and members of the Rice Group. It is expected that the special committee will engage independent counsel to assess the merits of the case and advise on the proper path forward for the Company.
Term Loan Agreement, dated as of May 31, 2019, by and among EQT Corporation, PNC Bank, National Association, as administrative agent, and the lenders party thereto
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.
