BAYTEX ENERGY USA, INC. - Quarter Report: 2020 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

________________________________________________________

(Mark One)


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________


Virginia						23-1184320
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification Number)

16285 PARK TEN PLACE, SUITE 500

HOUSTON, TX 77084

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(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

Common Stock, $0.01 Par Value

PVAC

Nasdaq Global Select Market

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 (“Exchange Act”) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically 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). Yes ☒ 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.

Large Accelerated Filer

☐

Accelerated Filer

☒

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐

As of July 31, 2020, 15,175,667 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended June 30, 2020

Table of Contents


Part I - Financial Information
Item		Page
1.	Financial Statements - unaudited.
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements:
	1. Nature of Operations	7
	2. Basis of Presentation	7
	3. Acquisitions and Divestitures	8
	4. Accounts Receivable and Revenues from Contracts with Customers	8
	5. Derivative Instruments	10
	6. Property and Equipment	13
	7. Long-Term Debt	13
	8. Income Taxes	15
	9. Leases	16
	10. Supplemental Balance Sheet Detail	17
	11. Fair Value Measurements	18
	12. Commitments and Contingencies	19
	13. Shareholders’ Equity	20
	14. Share-Based Compensation and Other Benefit Plans	21
	15. Interest Expense	22
	16. Earnings per Share	22
Forward-Looking Statements			23
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Overview and Executive Summary	24
	Key Developments	27
	Financial Condition	30
	Results of Operations	34
	Off Balance Sheet Arrangements	41
	Critical Accounting Estimates	41
3.	Quantitative and Qualitative Disclosures About Market Risk.	41
4.	Controls and Procedures.	43
Part II - Other Information
1.	Legal Proceedings.	44
1A.	Risk Factors.	44
5.	Other Information	44
6.	Exhibits.	45
Signatures			46

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Revenues
Crude oil	$	41,197	$	114,031	$	127,505	$	208,843
Natural gas liquids	1,578		3,502		3,471		9,050
Natural gas	2,020		5,290		4,710		9,567
Gain on sales of assets, net	8		16		14		41
Other revenues, net	679		(72)		1,161		494
Total revenues	45,482		122,767		136,861		227,995
Operating expenses
Lease operating	9,094		10,362		19,626		21,366
Gathering, processing and transportation	5,593		6,408		11,037		10,337
Production and ad valorem taxes	2,630		7,579		8,784		13,271
General and administrative	7,986		6,232		15,216		13,297
Depreciation, depletion and amortization	37,135		44,298		77,853		83,168
Impairment of oil and gas properties	35,509		—		35,509		—
Total operating expenses	97,947		74,879		168,025		141,439
Operating income (loss)	(52,465)		47,888		(31,164)		86,556
Other income (expense)
Interest expense	(8,536)		(9,056)		(16,716)		(18,534)
Derivatives	(34,349)		13,603		116,770		(54,414)
Other, net	(55)		8		(63)		114

Income (loss) before income taxes	(95,405)		52,443		68,827		13,722
Income tax (expense) benefit	690		(818)		(448)		(794)
Net income (loss)	$	(94,715)	$	51,625	$	68,379	$	12,928
Net income (loss) per share:
Basic	$	(6.24)	$	3.42	$	4.51	$	0.86
Diluted	$	(6.24)	$	3.40	$	4.48	$	0.85

Weighted average shares outstanding – basic	15,167		15,106		15,159		15,102
Weighted average shares outstanding – diluted	15,167		15,162		15,268		15,174

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Net income (loss)	$	(94,715)	$	51,625	$	68,379	$	12,928
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax	(1)		(1)		(2)		(2)
	(1)		(1)		(2)		(2)
Comprehensive income (loss)	$	(94,716)	$	51,624	$	68,377	$	12,926

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)


	June 30,		December 31,
	2020		2019
Assets
Current assets
Cash and cash equivalents	$	21,945	$	7,798
Accounts receivable, net of allowance for credit losses	42,833		70,716
Derivative assets	117,369		4,131
Income taxes receivable	—		1,236
Other current assets	4,141		4,458
Total current assets	186,288		88,339
Property and equipment, net (full cost method)	1,099,838		1,120,425
Derivative assets	4,053		2,750

Other assets	5,537		6,724
Total assets	$	1,295,716	$	1,218,238

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	55,924	$	105,824
Derivative liabilities	74,583		23,450
Total current liabilities	130,507		129,274
Other liabilities	9,578		8,382
Deferred income taxes	2,958		1,424
Derivative liabilities	8,900		3,385
Long-term debt, net	553,234		555,028

Commitments and contingencies (Note 12)

Shareholders’ equity:
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued	—		—
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,175,667 and 15,135,598 shares issued as of June 30, 2020 and December 31, 2019, respectively	152		151
Paid-in capital	202,158		200,666
Retained earnings	388,290		319,987
Accumulated other comprehensive loss	(61)		(59)
Total shareholders’ equity	590,539		520,745
Total liabilities and shareholders’ equity	$	1,295,716	$	1,218,238

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Six Months Ended June 30,
	2020		2019
Cash flows from operating activities
Net income	$	68,379	$	12,928
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization	77,853		83,168
Impairment of oil and gas properties	35,509		—
Derivative contracts:
Net (gains) losses	(116,770)		54,414
Cash settlements and premiums received (paid), net	58,877		(3,907)
Deferred income tax expense	1,534		2,030
Gain on sales of assets, net	(14)		(41)
Non-cash interest expense	2,537		1,748
Share-based compensation	1,807		2,055
Other, net	14		26
Changes in operating assets and liabilities, net	(831)		1,941
Net cash provided by operating activities	128,895		154,362

Cash flows from investing activities

Capital expenditures	(112,827)		(175,941)
Proceeds from sales of assets, net	83		29

Net cash used in investing activities	(112,744)		(175,912)

Cash flows from financing activities
Proceeds from credit facility borrowings	46,000		32,000
Repayment of credit facility borrowings	(49,000)		(13,000)

Debt issuance costs paid	(72)		(2,518)

Other, net	1,068		—
Net cash provided by (used in) financing activities	(2,004)		16,482
Net increase (decrease) in cash and cash equivalents	14,147		(5,068)
Cash and cash equivalents – beginning of period	7,798		17,864
Cash and cash equivalents – end of period	$	21,945	$	12,796

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	14,316	$	16,784
Income taxes, net of (refunds)	$	(2,471)	$	—
Reorganization items, net	$	—	$	79
Non-cash investing and financing activities:



Changes in accrued liabilities related to capital expenditures	$	(20,294)	$	17,397

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended June 30, 2020

(in thousands, except per share amounts or where otherwise indicated)

1. Nature of Operations

Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company focused on the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas. We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of crude oil, NGLs and natural gas.

2. Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements, have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2019. Operating results for the six months ended June 30, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020.

Adoption of Recently Issued Accounting Pronouncements

Effective January 1, 2020, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”). We adopted ASU 2016–13 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2020 (see Note 4 for the impact and disclosures associated with the adoption of ASU 2016–13). Comparative periods and related disclosures have not been restated for the application of ASU 2016–13.

Risks and Uncertainties

As an oil and gas exploration and development company, we are exposed to a number of risks and uncertainties that are inherent to our industry. In addition to such industry-specific risks, the global public health crisis associated with the novel coronavirus (“COVID-19”) has, and is anticipated to continue to have, an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy, which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of disagreements between the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia with respect to production curtailments.

As the breadth of the COVID-19 health crisis expanded and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately. In the second week of April, OPEC, Russia and certain other petroleum producing nations (“OPEC+”), reconvened and agreements were reached to cut production with certain allocations among the OPEC+ participants. Through July 2020, the OPEC+ production curtailment efforts have generally held and there have been modest recoveries of crude oil prices from their historic lows at the height of the COVID-19 health crisis; however, continued progress will be substantially impacted by further OPEC+ considerations in the second half of 2020.

Despite a significant decline in drilling by U.S. producers starting in mid-March 2020, domestic supply and demand imbalances continue to create operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region. Limited progress in containing the COVID-19 health crisis domestically, including the effects of recent spikes in many regions of the United States, including Texas, has hampered economic recovery. Furthermore, government stimulus and economic relief efforts initiated in the second quarter of 2020 are nearing expiration and will likely have to be extended or supplemented in some form in order to achieve meaningful economic recovery in the second half of 2020. These efforts are further impacted by election year uncertainties and related political conflicts. The combined effect of these aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.

During March and April 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position and liquidity. The more significant actions that we took during March and April 2020 included: (i) suspending our drilling and completion program (see Note 12), (ii) curtailing production through selected well shut-ins for a period of several weeks in April and May, (iii) securing crude oil storage capacity (see Note 12) in order to maintain a reasonable level of production to (a) allow for the continued marketing of NGLs and natural gas rather than delaying revenues through additional shut-ins and (b) capitalize on potential increases in commodity prices, (iv) substantially expanding the scope and range of our commodity derivatives portfolio (see Note 5) and (v) utilizing certain liquidity-related provisions of the Coronavirus Aid, Relief and Economic Security Act (the “CARES Act”) and related regulations, the most significant of which was the receipt in June 2020 an accelerated refund of our remaining refundable alternative minimum tax (“AMT”) credit carryforwards in the amount of $2.5 million.

Going Concern Presumption

Our unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business.

Subsequent Events

Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

3. Acquisitions

Eagle Ford Working Interests

In 2019, we acquired working interests in certain properties for which we are the operator from our joint venture partners therein for cash consideration of approximately $6.5 million. Funding for this acquisition was provided by borrowings under our credit agreement (the “Credit Facility”).

4. Accounts Receivable and Revenues from Contracts with Customers

Accounts Receivable and Major Customers

The following table summarizes our accounts receivable by type as of the dates presented:


	June 30,		December 31,
	2020		2019
Customers	$	40,944	$	63,165
Joint interest partners	2,046		6,929
Other	—		674
	42,990		70,768
Less: Allowance for credit losses	(157)		(52)
	$	42,833	$	70,716

For the six months ended June 30, 2020, four customers accounted for $99.2 million, or approximately 73%, of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2020, were $34.8 million, $26.3 million, $19.8 million and $18.3 million, or 26%, 19%, 15% and 13% of the consolidated total, respectively. As of June 30, 2020 and December 31, 2019, $29.0 million and $52.7 million, or approximately 71% and 83%, respectively, of our consolidated accounts receivable from customers was related to these customers. For the six months ended June 30, 2019, three customers accounted for $150.0 million, or approximately 66%, of our consolidated product revenues. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. As of June 30, 2020 and December 31, 2019, the allowance for credit losses is entirely attributable to receivables from joint interest partners.

Credit Losses and Allowance for Credit Losses

Adoption of ASU 2016–13

Effective January 1, 2020, we adopted ASU 2016–13 and have applied the guidance therein to our portfolio of accounts receivable including those from our customers and our joint interest partners. We have adopted ASU 2016–13 using the modified retrospective method resulting in an adjustment of less than $0.1 million to the beginning balance of retained earnings and a corresponding increase to the allowance for credit losses as of January 1, 2020.

Accounting Policies for Credit Losses

We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments which are described below: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10 percent in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10 percent in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable.

Customers. We sell our commodity products to approximately 15 customers. A substantial majority of these customers are large, internationally recognized refiners and marketers in the case of our crude oil sales and large domestic processors and interstate pipelines with respect to our NGL and natural gas sales. As noted in our disclosures regarding major customers above, a significant portion of our outstanding customer accounts receivable are concentrated within a group of up to five customers at any given time. Due primarily to the historical market efficiencies and generally timely settlements associated with commodity sale transactions for crude oil, NGLs and natural gas, we have assessed this portfolio segment at zero risk for credit loss upon the adoption of ASU 2016–13 and for each of the six months included in the period ended June 30, 2020. Historically, we have never experienced a credit loss with such customers including the periods during the 2008-2009 financial crisis and the more recent periods of significant commodity price declines. While we believe that the receivables that originated in June 2020 will be fully collected despite the ongoing uncertainty associated with the COVID-19 health crisis and the related global energy market disruptions, future originations of customer receivables will continue to be assessed with a greater emphasis on current economic conditions and reasonable supportable forecasts.

Mutual Operators. As of June 30, 2020, we had mutual joint interest partner relationships with three upstream producers that also operate properties within the Eagle Ford for which we have non-operated working interests. Historically we have had full and timely collection experiences with these entities and we ourselves are timely with respect to our payments to them of joint venture costs. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at zero risk for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have assessed receivables originating in 2020 with a five percent risk.

Large Partners. As of June 30, 2020, four legal entities had working interests of 10 percent or greater in properties that we operate. These entities are primarily passive investors. Historically we have had full and timely collection experiences with these entities. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at risk of one percent for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have increased the assessed receivables originating in 2020 to a two percent risk.

All Others. As of June 30, 2020, approximately thirty legal entities had working interests of less than 10 percent in properties that we operate. Historically, this is the only portfolio segment with whom we have experienced credit losses. Generally, this group includes passive investors and smaller producers that may not have the wherewithal or alternative sources of liquidity to settle their obligations to us in the event of individual challenges unique to smaller entities as well as adverse economic conditions in general. Upon adoption of ASU 2016–13, we had assessed this portfolio segment at a risk of five percent for credit loss; however, in light of the potential for liquidity concerns due to current economic conditions in the near-term, we have increased the assessed receivables originated in 2020 to a 10 percent risk. As of June 30, 2020, approximately $0.1 million of accounts receivables attributable to this portfolio segment was past due, or over 60 days.

Supplemental Disclosures

The following table summarizes the activity in our allowance for credit losses, by portfolio segment, for the six months ended June 30, 2020:


			Joint Interest Partners
	Customers		Mutual Operators		Large Partners		All Others		Total
Balance at beginning of period	$	—	$	—	$	—	$	52	$	52
Adjustment upon adoption	—		—		60		16		76
Provision for expected credit losses	—		5		13		11		29
Write-offs and recoveries	—		—		—		—		—
Balance at end of period	$	—	$	5	$	73	$	79	$	157

5. Derivative Instruments

We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges in the context of GAAP. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.

Commodity Derivatives

The following is a general description of the commodity derivative instruments we have employed:

Swaps. A swap contract is an agreement between two parties pursuant to which the parties exchange payments at specified dates on the basis of a specified notional amount, or the swap price, with the payments calculated by reference to specified commodities or indexes. The counterparty to a swap contract is required to make a payment to us based on the amount of the swap price in excess of the settlement price multiplied by the notional volume if the settlement price for any settlement period is below the swap price for such contract. We are required to make a payment to the counterparty based on the amount of the settlement price in excess of the swap price multiplied by the notional volume if the settlement price for any settlement period is above the swap price for such contract.

Put Options. A put option has a defined strike, or floor price. We have entered into put option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the put option pays the seller a premium to enter into the contract. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is above the floor price, the put option expires worthless. Certain of our purchased put options have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of settlement.

Call Options. A call option has a defined strike, or ceiling price. We have entered into call option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is below the ceiling price, the call option expires worthless.

We typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others.

We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions, including current market value and contractual prices for the underlying instruments, implied volatilities, time value and nonperformance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX West Texas Intermediate (“NYMEX WTI”), Magellan East Houston (“MEH”) crude oil and NYMEX Henry Hub (“NYMEX HH”) natural gas closing prices as of the end of the reporting period. Nonperformance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of June 30, 2020:


	3Q2020		4Q2020		1Q2021		2Q2021		3Q2021		4Q2021
NYMEX WTI Crude Swaps
Average Volume Per Day (barrels)	11,457		9,804		6,667		6,593
Weighted Average Swap Price ($/barrel)	$	51.17	$	55.18	$	48.73	$	48.73
NYMEX WTI Purchased Puts/Sold Calls
Average Volume Per Day (barrels)	4,043		2,000		3,333		3,297		3,261		3,261
Weighted Average Purchased Put Price ($/barrel)	$	52.70	$	48.00	$	47.50	$	47.50	$	40.00	$	40.00
Weighted Average Sold Call ($/barrel)	$	58.26	$	57.10	$	51.51	$	51.51	$	50.00	$	50.00
NYMEX WTI Purchased Puts
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	55.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	674
Weighted Average Purchased Put ($/barrel)	$	48.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	37.00
Weighted Average Deferred Premium ($/barrel)	$	1.23
Average Volume Per Day (barrels)	2,717
Weighted Average Purchased Put ($/barrel)	$	30.00
Weighted Average Deferred Premium ($/barrel)	$	3.63
Average Volume Per Day (barrels)					2,500		2,473
Weighted Average Purchased Put ($/barrel)					$	36.00	$	36.00
Weighted Average Premium ($/barrel)					$	4.50	$	4.50
NYMEX WTI Put Spread
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	39.00
Weighted Average Put Spread Sold Put ($/barrel)	$	32.00
Weighted Average Deferred Premium ($/barrel)	$	3.25
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	30.00
Weighted Average Put Spread Sold Put ($/barrel)	$	20.00
Weighted Average Deferred Premium ($/barrel)	$	2.45
NYMEX WTI Sold Puts
Average Volume Per Day (barrels)			5,087		10,833		10,714		3,261		3,261
Weighted Average Sold Put Price ($/barrel)			$	43.50	$	37.00	$	37.00	$	35.00	$	35.00
MEH Crude Swaps
Average Volume Per Day (barrels)	2,000		2,000
Weighted Average Swap Price ($/barrel)	$	61.03	$	61.03
MEH-NYMEX WTI Crude Basis Swaps
Average Volume Per Day (barrels)	10,870
Weighted Average Swap Price ($/barrel)	$	1.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (barrels)	10,870
Weighted Average Swap Price ($/barrel)	$	(0.45)
NYMEX HH Purchased Puts/Sold Calls
Average Volume Per Day (MMBtus)	12,804		12,804		3,333		3,297		3,261		3,261
Weighted Average Purchased Put ($/MMBtu)	$	2.00	$	2.00	$	2.50	$	2.50	$	2.50	$	2.50
Weighted Average Sold Call ($/MMBtu)	$	2.21	$	2.21	$	2.85	$	2.85	$	2.85	$	2.85

As of June 30, 2020, we were unhedged with respect to NGL production.

Interest Rate Derivatives

We have entered into a series of interest rate swap contracts (the “Interest Rate Swaps”) to establish fixed interest rates on a portion of our variable interest rate indebtedness under the Credit Facility and Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”). The notional amount of the Interest Rate Swaps totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to a customary London interbank offered rate (“LIBOR”) through May 2022.

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included in the “Derivatives” caption on our Condensed Consolidated Statements of Operations. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Condensed Consolidated Statements of Cash Flows under “Net (gains) losses” and “Cash settlements, net.”

The following table summarizes the effects of our derivative activities for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Interest rate swap losses recognized in the Consolidated Statements of Operations	$	(876)	$	—	$	(7,559)	$	—
Commodity gains (losses) recognized in the Consolidated Statements of Operations	(33,473)		13,603		124,329		(54,414)
	$	(34,349)	$	13,603	$	116,770	$	(54,414)

Interest rate cash settlements recognized in the Consolidated Statements of Cash Flows	$	(436)	$	—	$	(368)	$	—
Commodity cash settlements and premiums received (paid) recognized in the Consolidated Statements of Cash Flows	59,582		(8,301)		59,245		(3,907)
	$	59,146	$	(8,301)	$	58,877	$	(3,907)

The following table summarizes the fair values of our derivative instruments presented on a gross basis, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:


		June 30, 2020						December 31, 2019
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities - current	$	—	$	2,949	$	—	$	—
Commodity contracts	Derivative assets/liabilities – current	117,369		71,634		4,131		23,450
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		4,242		—		—
Commodity contracts	Derivative assets/liabilities – noncurrent	4,053		4,658		2,750		3,385
		$	121,422	$	83,483	$	6,881	$	26,835

As of June 30, 2020, we reported net commodity derivative assets of $45.1 million and net Interest Rate Swap liabilities of $7.2 million. The contracts associated with these positions are with seven counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in the Credit Facility. This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions.

The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

6. Property and Equipment

The following table summarizes our property and equipment as of the dates presented:


	June 30,		December 31,
	2020		2019
Oil and gas properties:
Proved	$	1,501,291	$	1,409,219
Unproved	52,142		53,200
Total oil and gas properties	1,553,433		1,462,419
Other property and equipment	27,470		25,915
Total properties and equipment	1,580,903		1,488,334
Accumulated depreciation, depletion and amortization	(481,065)		(367,909)
	$	1,099,838	$	1,120,425

Unproved property costs of $52.1 million and $53.2 million have been excluded from amortization as of June 30, 2020 and December 31, 2019, respectively. We transferred $4.4 million and less than $0.1 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest, from unproved properties to the full cost pool during the six months ended June 30, 2020 and 2019, respectively. We capitalized internal costs of $1.2 million and $2.2 million and interest of $1.4 million and $2.2 million during the three and six months ended June 30, 2020 and 2019, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $16.66 and $17.49 for the six months ended June 30, 2020 and 2019, respectively.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes (the “Ceiling Test”). As of June 30, 2020, the carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test by $35.5 million. Accordingly, we recorded an impairment of our oil and gas properties by this amount in the three months ended June 30, 2020. Because the Ceiling Test utilizes commodity prices based on a trailing twelve month average, it does not, as of June 30, 2020, fully reflect the substantial decline in commodity prices due to the economic impact of the COVID-19 health crisis and the ongoing disruption in global energy markets. Accordingly, we may incur additional impairments during the second half of 2020.

7. Long-Term Debt

The following table summarizes our debt obligations as of the dates presented:


	June 30, 2020						December 31, 2019
	Principal		Unamortized Discount and Deferred Issuance Costs ^{1, 2}		Principal		Unamortized Discount and Deferred Issuance Costs ^{1, 2}
Credit facility	$	359,400			$	362,400
Second lien term loan	200,000		$	6,166	200,000		$	7,372
Totals	559,400		$	6,166	562,400		$	7,372
Less: Unamortized discount ²	(2,019)				(2,415)
Less: Unamortized deferred issuance costs ^{1, 2}	(4,147)				(4,957)
Long-term debt, net	$	553,234			$	555,028

_______________________

¹ Excludes issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 10) and are being amortized over the term of the Credit Facility using the straight-line method.

² Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method.

Credit Facility

In April 2020, we entered into the Borrowing Base Redetermination Agreement and Amendment No. 7 to Credit Agreement (the “Seventh Amendment”). The Seventh Amendment, which became effective on April 30, 2020, provides a $1.0 billion revolving commitment and initially provided for a $400 million borrowing base, including a $25 million sublimit for the issuance of letters of credit. The borrowing base decreased to $375 million in accordance with the terms of the Seventh Amendment effective July 1, 2020 and, effective October 1, 2020, availability under the Credit Facility is further limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021. During the six months ended June 30, 2020, we incurred and capitalized approximately $0.1 million of issue and other costs associated with the Seventh Amendment, respectively and wrote-off $0.9 million of previously capitalized issue costs due to the decrease in the borrowing base associated with the Seventh Amendment. Availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base, provided that effective October 1, 2020, availability under the Credit Facility is limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and October of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital. We had $0.4 million in letters of credit outstanding as of June 30, 2020 and December 31, 2019.

The Credit Facility is scheduled to mature in May 2024; provided that on June 30, 2022, unless we have either extended the maturity date of the Second Lien Facility described below to a date that is at least 91 days after May 7, 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will be June 30, 2022.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including LIBOR through 2021, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one, three or six months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of June 30, 2020, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.43%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on our ability or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets.

The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter of 3.50 to 1.00.

The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, weekly cash balance reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. In addition, the Credit Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million.

The Credit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.

As of June 30, 2020, and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Credit Facility.

Second Lien Facility

On September 29, 2017, we entered into the Second Lien Facility. We received net proceeds of $187.8 million from the Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of $8.2 million. The proceeds from the Second Lien Facility were used to fund a significant acquisition and related fees and expenses. The maturity date under the Second Lien Facility is September 29, 2022.

The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate, with a floor of 1.00%, plus an applicable margin of 7.00%. As of June 30, 2020, the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.00%. Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34%, resulting in an effective interest rate of 9.89%. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one or three months (including in three-month intervals if we select a six-month interest period), at our election and is computed on the basis of a 360-day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): 101% of the amount being prepaid through September 2020; and thereafter, no premium. The Second Lien Facility also provides for a 101% prepayment premium in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility through September 2020, but no prepayment premium thereafter.

The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the Guarantor Subsidiaries.

The Second Lien Facility has no financial covenants, but contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends and transactions with affiliates and other customary covenants.

As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term loans. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility.

As of June 30, 2020, and through the date upon which the Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Second Lien Facility.

8. Income Taxes

We recognized a federal and state income tax expense for the six months ended June 30, 2020 at the blended rate of 21.6%. The federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.7%, which is fully attributable to the State of Texas. The provision also reflects a reclassification of $1.2 million from deferred tax assets for our remaining refundable AMT credit carryforwards that were accelerated due to certain income tax provisions provided in the CARES Act. In June 2020, we received a refund of $2.5 million for the aforementioned AMT credit carryforwards. Our net deferred income tax liability balance of $3.0 million as of June 30, 2020 is fully attributable to the State of Texas and primarily related to property and equipment.

We recognized a federal and state income tax benefit for the six months ended June 30, 2019 at the blended rate of 21.6%; however, the federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 5.8% which related to Texas deferred tax expense.

We had no liability for unrecognized tax benefits as of June 30, 2020. There were no interest and penalty charges recognized during the periods ended June 30, 2020 and 2019. Tax years from 2015 forward remain open to examination by the major taxing jurisdictions to which the Company is subject; however, net operating losses originating in prior years are subject to examination when utilized.

9. Leases

Lease Arrangements and Supplemental Disclosures

We generally have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, crude oil storage tank capacity, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases included in the disclosures below are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs, crude oil storage tank capacity and our field compressors. During April 2020, we released our drilling rigs. Our primary variable lease was represented by our field gas gathering and gas lift agreement with a midstream service provider and the lease payments are charged on a volumetric basis at a contractual fixed rate.

The following table summarizes the components of our total lease cost for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Operating lease cost	$	220	$	194	$	430	$	357
Short-term lease cost	4,595		11,484		15,891		23,055
Variable lease cost	4,990		5,548		10,647		10,643
Less: Amounts charged as drilling costs ¹	(3,710)		(10,790)		(14,331)		(21,641)
Total lease cost recognized in the Condensed Consolidated Statement of Operations ²	$	6,095	$	6,436	$	12,637	$	12,414

___________________

¹Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs.

²Includes $2.8 million and $2.9 million and $5.6 million and $5.0 million recognized in Gathering, processing and transportation expense (“GPT”), $3.0 million and $ 3.3 million and $6.6 million and $7.1 million recognized in Lease operating expense (“LOE”) for the three and six months ended June 30, 2020 and 2019, respectively, and $0.2 million and $0.4 million recognized in General and administrative expense (“G&A”) for each of the three and six months ended June 30, 2020 and 2019, respectively.

The following table summarizes supplemental cash flow information related to leases for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	253	$	182	$	471	$	221
ROU assets obtained in exchange for lease obligations:
Operating leases ¹	$	—	$	753	$	306	$	3,325

___________________

¹Includes $2.5 million recognized upon the adoption of Accounting Standards Codification Topic 842 (“ASC842”) in 2019.

The following table summarizes supplemental balance sheet information related to leases as of the dates presented:


	June 30,			December 31,
	2020			2019
ROU assets – operating leases	$	2,734		$	2,740
Current operating lease obligations	$	886		$	847
Noncurrent operating lease obligations	2,142			2,232
Total operating lease obligations	$	3,028		$	3,079
Weighted-average remaining lease term – operating leases	3.6 years			4.1 years
Weighted-average discount rate – operating leases	3.25		%	5.97		%
Remaining maturities of operating lease obligations as of June 30, 2020:
2020	$	429
2021	894
2022	874
2023	872
2024 and thereafter	145
Total undiscounted lease payments	3,214
Less: imputed interest	(186)
Total operating lease obligations	$	3,028

10. Supplemental Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:


	June 30,		December 31,
	2020		2019
Other current assets:
Tubular inventory and well materials	$	2,995	$	2,989
Prepaid expenses	1,146		1,469

	$	4,141	$	4,458
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	2,693	$	3,952
Right-of-use assets – operating leases	2,734		2,740

Other	110		32
	$	5,537	$	6,724
Accounts payable and accrued liabilities:
Trade accounts payable	$	10,706	$	30,098
Drilling costs	10,888		18,832
Royalties	23,045		44,537
Production, ad valorem and other taxes	4,874		3,244
Compensation	3,309		5,272
Interest	591		730
Current operating lease obligations	886		847
Other	1,625		2,264
	$	55,924	$	105,824
Other liabilities:
Asset retirement obligations	$	5,183	$	4,934
Noncurrent operating lease obligations	2,142		2,232
Defined benefit pension obligations	814		873
Postretirement health care benefit obligations	371		343
Other	1,068		—
	$	9,578	$	8,382

11. Fair Value Measurements

We apply the authoritative accounting provisions included in GAAP for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. As of June 30, 2020, the carrying values of all of these financial instruments approximated fair value.

Recurring Fair Value Measurements

Certain financial assets and liabilities are measured at fair value on a recurring basis on our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and (liabilities) as of the dates presented:


	As of June 30, 2020
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:
Interest rate swap assets – current	$	—	$	—	$	—	$	—
Interest rate swap assets – noncurrent	$	—	$	—	$	—	$	—
Commodity derivative assets – current	$	117,369	$	—	$	117,369	$	—
Commodity derivative assets – noncurrent	$	4,053	$	—	$	4,053	$	—
Liabilities:
Interest rate swap liabilities – current	$	(2,949)	$	—	$	(2,949)	$	—
Interest rate swap liabilities – noncurrent	$	(4,242)	$	—	$	(4,242)	$	—
Commodity derivative liabilities – current	$	(71,634)	$	—	$	(71,634)	$	—
Commodity derivative liabilities – noncurrent	$	(4,658)	$	—	$	(4,658)	$	—


	As of December 31, 2019
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:
Commodity derivative assets – current	$	4,131	$	—	$	4,131	$	—
Commodity derivative assets – noncurrent	$	2,750	$	—	$	2,750	$	—
Liabilities:
Commodity derivative liabilities – current	$	(23,450)	$	—	$	(23,450)	$	—
Commodity derivative liabilities – noncurrent	$	(3,385)	$	—	$	(3,385)	$	—

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the six months ended June 30, 2020 and 2019.

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

•Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH natural gas closing prices as of the end of the reporting periods. Each of these is a Level 2 input.

•Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique that connects future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input.

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as Level 3 inputs.

12. Commitments and Contingencies

Drilling and Completion Commitments

In March 2020, we provided termination notices releasing our contracted drilling rigs in connection with the suspension of our drilling and completion program. Costs of $1.6 million associated with the demobilization of the rigs in connection with their release were capitalized to our full cost pool. In April 2020, we rescinded one of the termination notices and entered into a new agreement to maintain one rig in place for a minimal daily rate providing us with the option to either restart drilling operations on seven days’ notice or release the rig altogether for demobilization. This rig was subsequently released in June 2020. Costs of $0.4 million associated with maintaining this rig on a standby basis were also capitalized to our full cost pool.

We also have a one-year agreement that became effective January 1, 2020, which can be terminated with 30 days’ notice by either party, for certain frac services and related materials, with no minimum commitment. We did not incur any costs under this agreement from mid-April through May 2020 due to the suspension of the drilling and completion program. We began to incur costs under this agreement in June 2020 upon the resumption of completion activities for wells that were drilled but uncompleted at the time of the suspension.

Crude Oil Storage

In March 2020, we secured crude oil storage capacity with Nuevo Dos Gathering and Transportation, LLC (“Nuevo G&T”) for up to 70,000 barrels per month for May and June 2020 as a supplement to our current dedicated capacity of approximately 150,000 barrels of working capacity at Nuevo G&T’s central delivery point facility in Lavaca County, Texas. In June 2020, we extended this agreement with Nuevo G&T through October 2020. The total remaining obligation under this agreements was $0.1 million as of June 30, 2020. In April 2020, we secured additional crude oil storage capacity for up to approximately 90,000 barrels of working capacity with a downstream interstate pipeline at their facility in DeWitt County, Texas, for up to six months beginning in May 2020. The total remaining obligation under this agreement is approximately $0.3 million as of June 30, 2020. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT.

Gathering and Intermediate Transportation Commitments

We have long-term agreements with Nuevo G&T and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”) to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in as well as volume capacity support for certain downstream interstate pipeline transportation.

Nuevo is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment (“MVC”) of 8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. We are obligated to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca and Fayette Counties, Texas.

Under a marketing agreement, we have a commitment to sell 8,000 barrels per day of crude oil (gross) to Nuevo, or to any third party, utilizing Nuevo Marketing’s capacity on a downstream interstate pipeline through 2026.

Under each of the agreements with Nuevo, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period.

Excluding the application of existing credits that we have earned during the preceding 12-month period ended June 30, 2020 for deliveries of volumes in excess of the volume commitment, and the potential impact of the effects of price escalation from commodity price changes, if any, the minimum fee requirements attributable to the MVC under the gathering and transportation agreement are as follows: $6.5 million for the remainder of 2020, $13.0 million per year for 2021 through 2025, $7.4 million for 2026, $3.8 million per year for 2027 through 2030 and $2.2 million for 2031.

Legal, Environmental Compliance and Other Claims

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of June 30, 2020, we had a reserve in the amount of $0.3 million included in “Accounts payable and accrued liabilities” for the estimated settlement of a dispute with a partner regarding certain transactions that occurred in prior years. As of June 30, 2020, we had AROs of approximately $5.2 million attributable to the plugging of abandoned wells. In June 2020, we provided for an estimated reserve of approximately $0.1 million for certain claims made against us regarding previously divested operations.

13. Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for the quarterly periods in 2020 and 2019.


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total Shareholders’ Equity
Balance as of December 31, 2019	$	151	$	200,666	$	319,987	$	(59)	$	520,745
Net income	—		—		163,094		—		163,094
Cumulative effect of change in accounting principle ¹	—		—		(76)		—		(76)
All other changes ²	1		556		—		(1)		556
Balance as of March 31, 2020	$	152	$	201,222	$	483,005	$	(60)	$	684,319
Net loss	—		—		(94,715)		—		(94,715)
All other changes ²	—		936		—		(1)		935
Balance as of June 30, 2020	$	152	$	202,158	$	388,290	$	(61)	$	590,539

_______________________

¹Attributable to the adoption of ASU 2016–13 as of January 1, 2020 (see Note 4).

² Includes equity-classified share-based compensation of $1.8 million during the six months ended June 30, 2020. During the six months ended June 30, 2020, 36,174 and 3,895 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes.


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Shareholders’ Equity
Balance as of December 31, 2018	$	151	$	197,630	$	249,492	$	82	$	447,355
Net loss	—		—		(38,697)		—		(38,697)
Cumulative effect of change in accounting principle ¹	—		—		(94)		—		(94)
All other changes ²	—		381		—		(1)		380
Balance as of March 31, 2019	$	151	$	198,011	$	210,701	$	81	$	408,944
Net income	—		—		51,625		—		51,625
All other changes ²	—		986		—		(1)		985
Balance as of June 30, 2019	$	151	$	198,997	$	262,326	$	80	$	461,554

_______________________

¹ Attributable to the adoption of ASC Topic 842 as of January 1, 2019 (see Note 9).

² Includes equity-classified share-based compensation of $2.1 million during the six months ended June 30, 2019. During the six months ended June 30, 2019, 26,671 shares of common stock were issued in connection with the vesting of certain RSUs, net of shares withheld for income taxes.

14. Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A expenses in our Condensed Consolidated Statements of Operations.

We reserved a total of 1,424,600 shares of common stock for issuance under the Penn Virginia Corporation Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of 584,497 RSUs and 201,491 PRSUs have been granted to employees and directors under the Plan through June 30, 2020. As of June 30, 2020, a total of 308,813 RSUs and 161,044 PRSUs are unvested and outstanding.

We recognized $1.0 million and $1.8 million of expense attributable to the RSUs and PRSUs for the three and six months ended June 30, 2020, respectively and $1.0 million and $2.1 million for the three and six months ended June 30, 2019 , respectively.

A total of 223,882 RSUs were granted during the six months ended June 30, 2020 with an average grant-date fair value of $2.78. A total of 1,132 equity awards were granted during the six months ended June 30, 2019 with an average grant-date fair value of $43.06. The RSUs are being charged to expense on a straight-line basis over a range of less than one to five years. In the six months ended June 30, 2020 and 2019, 36,174 and 26,671 shares were issued upon vesting/settlement of equity awards, net of shares withheld for income taxes, respectively.

During the six months ended June 30, 2020, 87,899 PRSUs were granted. No PRSUs were granted during the six months ended June 30, 2019. PRSUs were granted collectively in two to three separate tranches with individual three-year performance periods beginning in January 2017, 2018 and 2019, respectively for the pre-2019 grants. For the 2019 and 2020 grants, the performance period is 2020 through 2022. Vesting of the PRSUs can range from zero to 200 percent of the original grant based on the performance of our common stock relative to an industry index or, for the 2019 and 2020 grants, a defined peer group. Due to their market condition, the PRSUs are being charged to expense using graded vesting over a maximum of five years. The fair value of each PRSU award was estimated on their applicable grant date using a Monte Carlo simulation with a range of $47.70 to $65.28 per PRSU for the 2017 grants, $34.02 per PRSU for the 2019 grants and $2.40 per PRSU for the 2020 grants. In the six months ended June 30, 2020, 3,895 shares were issued upon settlement of equity awards, net of shares withheld for income taxes.

The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2020, 2019 and 2017 are presented as follows:


	2020		2019		2017
Expected volatility	101.32	%	49.9	%	59.63% to 62.18%
Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	0.51	%	1.66	%	1.44% to 1.51%

Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.2 million and $0.4 million of expense attributable to the 401(k) Plan for the three and six months ended June 30, 2020, respectively, and $0.1 million and $0.3 million for the three and six months ended June 30, 2019, respectively. The charges for the 401(k) Plan are recorded as a component of G&A expenses in our Condensed Consolidated Statements of Operation.

We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to 2000. The combined expense recognized with respect to these plans was less than $0.1 million for each of the three and six months ended June 30, 2020 and 2019. The charges for these plans are recorded as a component of “Other income (expense)” in our Condensed Consolidated Statements of Operation.

15. Interest Expense

The following table summarizes the components of interest expense for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Interest on borrowings and related fees	$	7,524	$	9,304	$	15,569	$	19,015
Accretion of original issue discount ¹	201		183		397		363
Amortization of debt issuance costs ²	1,513		644		2,140		1,385
Capitalized interest	(702)		(1,075)		(1,390)		(2,229)
	$	8,536	$	9,056	$	16,716	$	18,534

___________________

¹Attributable to the Second Lien Facility (see Note 7).

² Includes $0.9 million of accelerated amortization in the three and six months ended June 30, 2020 attributable to the reduction in the borrowing base associated with the Seventh Amendment.

16. Earnings per Share

The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:


	Three Months Ended June 30,						Six Months Ended June 30,
	2020		2019		2020		2019
Net income (loss) – basic and diluted	$	(94,715)	$	51,625	$	68,379	$	12,928

Weighted-average shares – basic	15,167		15,106		15,159		15,102
Effect of dilutive securities	—		56		109		72
Weighted-average shares – diluted	15,167		15,162		15,268		15,174

___________________

¹For the three months ended June 30, 2020, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We use words such as “anticipate,” “guidance,” “assumptions,” “projects,” “estimates,” “expects,” “continues,” “intends,” “plans,” “believes,” “forecasts,” “future,” “potential,” “may,” “possible,” “could” and variations of such words or similar expressions to identify forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•the decline in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas, including the recent dramatic decline of such prices;

•the impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders, interruptions to our operations or our customer’s operations;

•risks related to and the impact of actual or anticipated other world health events;

•risks related to acquisitions and dispositions, including our ability to realize their expected benefits;

•our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash flows from operations or to obtain adequate financing, including access to the capital markets, to fund our capital expenditures and meet working capital needs;

•negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

•plans, objectives, expectations and intentions contained in this report that are not historical;

•our ability to execute our business plan in volatile and depressed commodity price environments;

•our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;

•our ability to realize expected benefits of suspensions or other changes to our drilling and development program;

•our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;

•our ability to meet guidance, market expectations and internal projections, including type curves;

•any impairments, write-downs or write-offs of our reserves or assets;

•the projected demand for and supply of oil, NGLs and natural gas;

•our ability to contract for drilling rigs, frac crews, materials, supplies and services at reasonable costs;

•our ability to renew or replace expiring contracts on acceptable terms;

•our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;

•the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and gas reserves;

•use of new techniques in our development, including choke management and longer laterals;

•drilling, completion and operating risks, including adverse impacts associated with well spacing and a high concentration of activity;

•our ability to compete effectively against other oil and gas companies;

•leasehold terms expiring before production can be established and our ability to replace expired leases;

•environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;

•the timing of receipt of necessary regulatory permits;

•the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations;

•the occurrence of unusual weather or operating conditions, including force majeure events;

•our ability to retain or attract senior management and key employees;

•our reliance on a limited number of customers and a particular region for substantially all of our revenues and production;

•compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;

•physical, electronic and cybersecurity breaches;

•uncertainties relating to general domestic and international economic and political conditions;

•the impact and costs associated with litigation or other legal matters;

•sustainability initiatives; and

•other factors set forth in our filings with the Securities and Exchange Commission, or SEC, including the risks set forth in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 and in Part II, Item 1A of the Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

The effects of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of these factors.

Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its consolidated subsidiaries (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Part I, Item 1, “Financial Statements.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain statistics for the periods ended June 30, 2019 have been reclassified to conform to the 2020 presentation. References to “quarters” represent the three months ended June 30, 2020 or 2019, as applicable.

Overview and Executive Summary

We are an independent oil and gas company focused on the onshore exploration, development and production of crude oil, natural gas liquids, or NGLs, and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale, or the Eagle Ford, in Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.

Industry Environment and Recent Operating and Financial Highlights

Commodity Price and Other Economic Conditions

The global public health crisis associated with the novel coronavirus, or COVID-19, has, and is anticipated to continue to have, an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy, which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of disagreements between the Organization of the Petroleum Exporting Countries, or OPEC, and Russia with respect to recommended production curtailments.

As the breadth of the COVID-19 health crisis expanded and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity declined commensurately. In the second week of April, OPEC, Russia and certain other petroleum producing nations, or OPEC+, reconvened and agreements were reached to cut production with certain allocations among the OPEC+ participants. Through July 2020, the OPEC+ production curtailment efforts have generally held, and there have been modest recoveries of crude oil prices from their historic lows at the height of the COVID-19 health crisis; however, continued progress will be substantially impacted by domestic developments and further OPEC+ considerations in the second half of 2020.

The combined effect of COVID-19 and the energy industry disruptions led to a decline in NYMEX West Texas Intermediate, or NYMEX WTI, crude oil prices of approximately 36 percent from the beginning of January 2020, when prices were approximately $62 per barrel, through the end of June 2020, when they were just below $40 per barrel. Crude oil prices were well below $20 per barrel and included one trading day in a negative position during the second half of April 2020. Prices began to increase and stabilized following the implementation of the aforementioned OPEC+ production curtailments and proactive economic relief efforts in many countries, including the United States. Despite recent modest improvements in prices, overall crude oil pricing remains subject to significant volatility as broader economic recovery, particularly in the United States, has not progressed to a level to substantially increase energy demand.

Despite a significant decline in drilling by U.S. producers that began in mid-March 2020, domestic supply and demand imbalances continue to create operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region. Limited progress in containing the COVID-19 health crisis domestically, including the effects of recent spikes in many regions of the United States has further hampered domestic economic recovery. Furthermore, government stimulus and economic relief efforts initiated in the second quarter of 2020 are nearing expiration and will likely have to be extended or supplemented in some form in order to achieve meaningful economic recovery in the second half of 2020. These efforts are further impacted by election year uncertainties and related political conflicts. The combined effect of these and the international factors referenced above is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.

During March and April 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position and liquidity. The more significant actions that we took during March and April 2020 included: (i) suspending our drilling and completion program, (ii) curtailing production through selected well shut-ins for a period of several weeks in April and May, (iii) securing crude oil storage capacity in order to maintain a reasonable level of production to (a) allow for the continued marketing of NGLs and natural gas rather than delaying revenues through additional shut-ins and (b) capitalize on potential increases in commodity prices, (iv) substantially expanding the scope and range of our commodity derivatives portfolio and (v) utilizing certain liquidity-related provisions of the Coronavirus Aid, Relief and Economic Security Act, or the CARES Act and related regulations.

These actions are described in greater detail in the discussions for Key Developments that follow as well as Notes 2, 5, 8 and 12 to the Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements.”

Capital Expenditures and Development Progress

In April 2020 we formally suspended our drilling and completion program, subject to change based on trends in commodity prices, and released all of our contracted drilling rigs. In June 2020, we re-engaged completion activities for wells that were drilled but uncompleted at the time of the suspension. We turned three gross (2.8 net) of these wells to sales in June 2020. Any further resumption of our drilling and completion program will be dependent on trends in commodity prices, which our management team continues to monitor.

During the first half of 2020, we incurred capital expenditures of approximately $90 million with 96 percent directed to drilling and completion projects. We drilled and completed a total of 16 gross (13.8 net) wells through June 30, 2020.

Sequential Quarterly Analysis

The following summarizes our key operating and financial highlights for the three months ended June 30, 2020, with comparison to the three months ended March 31, 2020 as presented in the table that follows. The year-over-year highlights for the quarterly periods ended June 30, 2020 and 2019 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.

•Daily production decreased eight percent to 24,617 barrels of oil equivalent per day, or BOEPD, from 26,740 BOEPD due primarily to the suspension of our drilling program in April 2020, as well as our shutting-in production for a substantial number of our wells for several weeks during April and May of 2020. Total production decreased eight percent to 2,240 thousand barrels of oil equivalent, or MBOE, from 2,433 MBOE due primarily to the drilling suspension and production shut-ins referenced above during the quarter ended June 30, 2020.

•Product revenues declined approximately 51 percent to $44.8 million from $90.9 million due primarily to 48 percent lower crude oil prices, or $37.7 million, and nine percent lower crude oil volume, or $7.4 million. NGL revenues were 17 percent lower due to 15 percent lower prices, or $0.3 million, and one percent lower volume, or less than $0.1 million. Natural gas revenues declined 25 percent due to 16 percent lower prices, or $0.4 million, and 11 percent lower volume, or $0.3 million.

•Production and lifting costs (consisting of Lease operating expenses, or LOE, and Gathering, processing and transportation expenses, or GPT) decreased on an absolute basis to $14.7 million from $16.0 million and declined marginally on a per unit basis to $6.56 per BOE from $6.57 per BOE due primarily to the effects of lower production volume. Lower gas lift, chemicals, water disposal, utilities and repairs and maintenance costs primarily associated with the lower production volume were partially offset by crude oil storage charges.

•Production and ad valorem taxes decreased on an absolute and per unit basis to $2.6 million and $1.17 per BOE from $6.2 million and $2.53 per BOE, respectively, due to the overall effects of substantially lower product pricing and lower volume as well as the effect of lower than anticipated ad valorem tax assessments.

•General and administrative, or G&A, expenses increased on an absolute and per unit basis to $8.0 million and $3.56 per BOE from $7.2 million and $2.97 per BOE, respectively, due primarily to higher consulting and incentive and share-based compensation costs in the second quarter of 2020.

•Depreciation, depletion and amortization, or DD&A, decreased on an absolute and per unit basis to $37.1 million and $16.58 per BOE from $40.7 million and $16.73 per BOE due primarily to lower volume.

•We recorded an impairment of our oil and gas properties of $35.5 million as the unamortized cost of our oil and gas properties, net of deferred income taxes, exceeded the sum of discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes, or the Ceiling Test. The impairment is primarily attributable to a decline in the trailing twelve-month average prices of crude oil, NGLs and natural gas.

•Due to the combined impact of the matters noted in the bullets above, we incurred an operating loss of $52.5 million in the second quarter of 2020 compared to operating income of $21.3 million in first quarter of 2020.

The following table sets forth certain historical summary operating and financial statistics for the periods presented:


	Three Months Ended															Six Months Ended
	June 30,			March 30,			June 30,			June 30,
	2020			2020			2019			2020			2019
Total production (MBOE)	2,240			2,433			2,534			4,674			4,756
Average daily production (BOEPD)	24,617			26,740			27,845			25,679			26,278
Crude oil production (MBbl)	1,719			1,881			1,821			3,599			3,473
Crude oil production as a percent of total	77		%	77		%	72		%	77		%	73		%
Product revenues	$	44,795		$	90,891		$	122,823		$	135,686		$	227,460
Crude oil revenues	$	41,197		$	86,308		$	114,031		$	127,505		$	208,843
Crude oil revenues as a percent of total	92		%	95		%	93		%	94		%	92		%
Realized prices:
Crude oil ($ per Bbl)	$	23.97		$	45.90		$	62.63		$	35.42		$	60.14
NGLs ($ per Bbl)	$	5.21		$	6.16		$	9.01		$	5.69		$	12.85
Natural gas ($ per Mcf)	$	1.54		$	1.83		$	2.72		$	1.69		$	2.75
Aggregate ($ per BOE)	$	20.00		$	37.35		$	48.47		$	29.03		$	47.82
Prices adjusted for derivatives:
Crude oil ($ per Bbl)	$	50.37		$	54.15		$	59.02		$	52.34		$	57.76
Natural gas ($ per Mcf)	$	1.79		$	1.90		$	2.72		$	1.85		$	2.75
Aggregate ($ per BOE)	$	40.41		$	43.78		$	45.87		$	42.16		$	46.08
Production and lifting costs:
Lease operating ($ per BOE)	$	4.06		$	4.33		$	4.09		$	4.20		$	4.49
Gathering, processing and transportation ($ per BOE)	$	2.50		$	2.24		$	2.53		$	2.36		$	2.17
Production and ad valorem taxes ($ per BOE)	$	1.17		$	2.53		$	2.99		$	1.88		$	2.79
General and administrative ($ per BOE) ¹	$	3.56		$	2.97		$	2.46		$	3.26		$	2.80
Depreciation, depletion and amortization ($ per BOE)	$	16.58		$	16.73		$	17.48		$	16.66		$	17.49
Capital expenditure program costs ²	$	10,719		$	79,220		$	90,872		$	89,939		$	192,160
Cash provided by operating activities ³	$	56,422		$	72,473		$	85,103		$	128,895		$	154,362
Cash paid for capital expenditures ⁴	$	50,812		$	62,015		$	89,455		$	112,827		$	175,941
Cash and cash equivalents at end of period	$	21,945		$	55,331		$	12,796		$	21,945		$	12,796
Debt outstanding at end of period, net ⁵	$	553,234		$	592,624		$	531,476		$	553,234		$	531,476
Credit available under credit facility at end of period ⁶	$	40,200		$	100,200		$	159,600		$	40,200		$	159,600
Net development wells drilled and completed	2.8			11.0			7.3			13.8			15.1

^{__________________________________________________________________________________}

¹Includes combined amounts of $0.42, $0.35 and $0.43 per BOE for the three months ended June 30, 2020, March 31, 2020 and June 30, 2019, respectively, and $0.39 and $0.60 per BOE for the six months ended June 30, 2020 and 2019, respectively attributable to equity-classified share-based compensation and significant special charges, including acquisition, divestiture and strategic transaction and other costs, as described in the discussion of “Results of Operations – General and Administrative” that follows.

²Includes amounts accrued and excludes capitalized interest and capitalized labor.

³ Includes net cash received (paid) for derivative settlements and premiums received (paid) of $59.1 million, $(0.3) million and $(8.3) million for the three months ended June 30, 2020, March 31, 2020 and June 30, 2019, respectively, and $58.9 million and $(3.9) million for the six months ended June 30, 2020 and 2019, respectively. Reflects changes in operating assets and liabilities of $(16.9) million, $16.0 million and $8.4 million for the three months ended June 30, 2020, March 31, 2020 and June 30, 2019, respectively, and $(0.8) million and $1.9 million for the six months ended June 30, 2020 and 2019, respectively.

⁴ Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor.

⁵Represents amounts net of unamortized discount and deferred issue costs of $6.2 million, $6.8 million and $8.5 million as of June 30, 2020, March 31, 2020 and June 30, 2019, respectively.

⁶ The borrowing base under the credit agreement, or Credit Facility, was reduced to $400 million effective April 30, 2020 through June 30, 2020 at which time it was further decreased to $375 million. Effective October 1, 2020, availability under the Credit Facility will be limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021.

Key Developments

The following general business developments had or may have a significant impact on our results of operations, financial position and cash flows:

Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices

During the first half of 2020, we initiated and pursued several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position, liquidity and the efficient continuity of our operations as follows:

Drilling and Completion Program. We suspended our drilling and completion program in April 2020. All of our contracted operated rigs were released from drilling activities in early April 2020. See Note 12 to our Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements” for additional information.

Production Curtailment. In April 2020 we began shutting-in production on selected wells for a period of several weeks extending through mid-May 2020. As of June 30, 2020, all but 12 gross wells were back online and producing.

Crude Oil Storage. We secured supplemental storage capacity for our crude oil production through October 2020. See Note 12 to our Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements” for additional information. This additional storage capacity enabled us to store a significant portion of our May oil production and sell such production at an increased price in June 2020.

Derivatives. We substantially expanded the scope and range of our commodity derivatives portfolio and restructured certain oil hedge positions to move hedge positions from the second half of 2021 into the second and the fourth quarters of 2020. In the second quarter of 2020, we received approximately $60 million in net cash proceeds from settlements, net of premiums, of our commodity derivatives.

Federal Relief. We utilized a number of liquidity and income tax measures made available under the CARES Act and related regulations, the most significant of which was the application for an accelerated refund of our remaining alternative minimum tax, or AMT, credits of $2.5 million, which was received in June 2020, that would have otherwise been payable to us over the next two years.

Working Capital. We have negotiated more favorable payment terms with certain of our larger vendors and are continuing to increase our diligence in collecting and managing our portfolio of joint venture receivables.

Cost Containment. We eliminated annual cost-of-living and similar adjustments to our salaries and wages for 2020.

Borrowing Base Redetermination

On April 30, 2020, we entered into the Borrowing Base Redetermination Agreement and Amendment No. 7 to Credit Agreement, or the Seventh Amendment. The Seventh Amendment, which became effective on April 30, 2020, provides a $1.0 billion revolving commitment and initially provided for a $400 million borrowing base, including a $25 million sublimit for the issuance of letters of credit. The borrowing base decreased to $375 million in accordance with the terms of the Seventh Amendment effective July 1, 2020 and, effective October 1, 2020, availability under the Credit Facility is further limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021. In addition, the Seventh Amendment provides for: (i) an increase of 100 basis points to the applicable margin ranges for outstanding borrowings, (ii) a decrease to the maximum leverage ratio from 4.00 times to 3.50 times, (iii) implementation of certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million and (iv) further limitations on dividends and share repurchases until Spring 2021 borrowing base determination.

Commodity Hedging Program

As of July 31, 2020, we have hedged a portion of our estimated future crude oil and natural gas production from August 1, 2020 through the first half of 2021. We are currently unhedged with respect to NGL production. The following table summarizes our net hedge positions for the periods presented:


	3Q2020		4Q2020		1Q2021		2Q2021		3Q2021		4Q2021
NYMEX WTI Crude Swaps
Average Volume Per Day (barrels)	12,543		9,804		5,000		4,945
Weighted Average Swap Price ($/barrel)	$	50.31	$	55.18	$	51.60	$	51.60
NYMEX WTI Purchased Puts/Sold Calls
Average Volume Per Day (barrels)	4,043		2,000		5,000		4,945		3,261		3,261
Weighted Average Purchased Put Price ($/barrel)	$	52.70	$	48.00	$	45.00	$	45.00	$	40.00	$	40.00
Weighted Average Sold Call ($/barrel)	$	58.26	$	57.10	$	50.06	$	50.06	$	50.00	$	50.00
NYMEX WTI Purchased Puts
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	55.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	674
Weighted Average Purchased Put ($/barrel)	$	48.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	37.00
Weighted Average Deferred Premium ($/barrel)	$	1.23
Average Volume Per Day (barrels)	2,717
Weighted Average Purchased Put ($/barrel)	$	30.00
Weighted Average Deferred Premium ($/barrel)	$	3.63
Average Volume Per Day (barrels)					2,500		2,473
Weighted Average Purchased Put ($/barrel)					$	36.00	$	36.00
Weighted Average Premium ($/barrel)					$	4.50	$	4.50
NYMEX WTI Put Spread
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	39.00
Weighted Average Put Spread Sold Put ($/barrel)	$	32.00
Weighted Average Deferred Premium ($/barrel)	$	3.25
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	30.00
Weighted Average Put Spread Sold Put ($/barrel)	$	20.00
Weighted Average Deferred Premium ($/barrel)	$	2.45
NYMEX WTI Sold Puts
Average Volume Per Day (barrels)			5,087		12,500		12,363		3,261		3,261
Weighted Average Sold Put Price ($/barrel)			$	43.50	$	36.73	$	36.73	$	35.00	$	35.00
MEH Crude Swaps
Average Volume Per Day (barrels)	2,000		2,000
Weighted Average Swap Price ($/barrel)	$	61.03	$	61.03
MEH-NYMEX WTI Crude Basis Swaps
Average Volume Per Day (barrels)	10,870
Weighted Average Swap Price ($/barrel)	$	1.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (barrels)	14,130
Weighted Average Swap Price ($/barrel)	$	(0.43)
NYMEX HH Purchased Puts/Sold Calls
Average Volume Per Day (MMBtus)	12,804		12,804		3,333		3,297		3,261		3,261
Weighted Average Purchased Put ($/MMBtu)	$	2.00	$	2.00	$	2.50	$	2.50	$	2.50	$	2.50
Weighted Average Sold Call ($/MMBtu)	$	2.21	$	2.21	$	2.85	$	2.85	$	2.85	$	2.85

Production and Development Plans

Total production for the second quarter of 2020 was 2,240 MBOE, or 24,617 BOEPD, with approximately 77 percent, or 1,719 MBbls, of production from crude oil, 13 percent from NGLs and 10 percent from natural gas. We drilled and turned three gross (2.8 net) wells to sales during the second quarter of 2020. As of June 30, 2020, we had approximately 99,000 gross (86,500 net) acres in the Eagle Ford, net of expirations. Approximately 92 percent of our acreage is held by production and substantially all is operated by us.

Financial Condition

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to $1.0 billion in borrowing commitments. The borrowing base under the Credit Facility was $400 million through June 30, 2020 at which time it was further reduced to $375 million. Effective October 1, 2020, availability under the Credit Facility will be limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021. As of August 1, 2020, we had $40.2 million available under the Credit Facility.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been negatively impacted by the COVID-19 health crisis and the ongoing disruptions to the global energy markets. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in the Credit Facility, hedging a portion of our estimated future crude oil and natural gas production through the first half of 2021. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

Capital Resources

We plan to fund our operations for the next twelve months primarily with cash on hand, cash from operating activities, including net receipts from derivative settlements and borrowings under the Credit Facility. Based upon current price and production expectations for the remainder of the year, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility will be sufficient to fund our operations for the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic slowdown associated with the COVID-19 health crisis and related disruptions to global energy markets.

Cash on Hand and Cash From Operating Activities. As of July 31, 2020, we had approximately $10.5 million of cash on hand. For additional information and an analysis of our historical cash from operating activities, see the “Cash Flows” discussion that follows.

Credit Facility Borrowings. During the six months ended June 30, 2020, we repaid $3 million, net of borrowings, under the Credit Facility. For additional information regarding the terms and covenants under the Credit Facility, see the “Capitalization” discussion that follows.

The following table summarizes our borrowing activity under the Credit Facility for the periods presented:


			Borrowings Outstanding
	End of Period		Weighted- Average		Maximum		Weighted- Average Rate
Three months ended June 30, 2020	$	359,400	$	380,774	$	399,400	3.54	%
Six months ended June 30, 2020	$	359,400	$	378,416	$	399,400	3.61	%

Proceeds from Sales of Assets. For additional information and an analysis of our historical proceeds from sales of assets, see the “Cash Flows” discussion that follows.

Capital Markets Transactions. From time-to-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality.

Cash Flows

The following table summarizes our cash flows for the periods presented:


	Six Months Ended
	June 30,		June 30,
	2020		2019
Cash flows from operating activities
Operating cash flows, net of working capital changes	$	82,231	$	177,117
Crude oil derivative settlements and premiums received (paid), net	59,245		(3,907)
Natural gas derivative settlements received, net	(368)		—
Interest payments, net of amounts capitalized	(14,316)		(16,784)
Interest rate swap settlements paid, net	(368)		—
Income tax refunds	2,471		—
Acquisition, divestiture and strategic transaction costs paid	—		(1,985)
Reorganization-related administration fees and costs paid	—		(79)

Net cash provided by operating activities	128,895		154,362
Cash flows from investing activities

Capital expenditures	(112,827)		(175,941)
Proceeds from sales of assets, net	83		29

Net cash used in investing activities	(112,744)		(175,912)
Cash flows from financing activities
Proceeds from credit facility borrowings, net	(3,000)		19,000
Debt issuance costs paid	(72)		(2,518)
Other, net	1,068		—
Net cash provided by (used in) financing activities	(2,004)		16,482
Net increase (decrease) in cash and cash equivalents	$	14,147	$	(5,068)

Cash Flows from Operating Activities. The decrease of $25.5 million in net cash provided by operating activities for the six months ended June 30, 2020 compared to the corresponding period in 2019 was primarily attributable to the substantial decline in commodity prices resulting from the adverse impact of COVID-19 on the global economy and disruptions in the global energy markets as well as marginally lower total production, each of which substantially decreased our realized product revenues. The adverse impact on cash received from realized revenues was partially offset by:(i) substantially higher receipts from derivatives settlements in the 2020 period, particularly in the second quarter of 2020, (ii) lower interest payments due to substantially lower weighted-average variable rates despite higher outstanding borrowings in the 2020 period, (iii) the receipt of an alternative minimum tax credit carryforward that was accelerated as a result of the CARES Act, (iv) the absence in the 2020 period of acquisition, divestiture, strategic transaction and reorganization-related administration fees and costs that were paid in the 2019 period, (v) the beneficial impact in the 2020 period of cost containment efforts in both our operations and administrative functions including lower discretionary maintenance and cost deferrals consistent with lower levels of business activity, the elimination of cost-of-living and similar adjustments to our salaries and wages and (vi) improved working capital management.

Cash Flows from Investing Activities. As illustrated in the tables below, our cash payments for capital expenditures were significantly lower during the 2020 period as compared to the 2019 period, due primarily to a suspension of the drilling and completion program during a portion of the 2020 period. Lower payments in the 2020 period were also impacted by the extension of payment periods with certain of our larger drilling and completion vendors. In addition, we received marginally higher proceeds from the sale of scrap tubular and well materials in the 2020 period compared to the 2019 period.

The following table sets forth costs related to our capital expenditures program for the periods presented:


	Six Months Ended
	June 30,		June 30,
	2020		2019
Drilling and completion	$	86,312	$	185,649
Lease acquisitions and other land-related costs	2,562		1,383
Pipeline, gathering facilities and other equipment, net	1,056		4,817
Geological and geophysical (seismic) costs	9		311
	$	89,939	$	192,160

The following table reconciles the total costs of our capital expenditures program with the net cash paid for capital expenditures as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:


	Six Months Ended
	June 30,		June 30,
	2020		2019
Total capital expenditures program costs (from above)	$	89,939	$	192,160
Decrease (increase) in accounts payable for capital items and accrued capitalized costs	20,294		(17,397)
Less:
Transfers from tubular inventory and well materials	(4,322)		(3,458)
Sales and use tax refunds received and applied to property accounts	—		(2,855)
Other, net	—		(32)
Add:
Tubular inventory and well materials purchased in advance of drilling	4,328		3,130
Capitalized internal labor	1,198		2,164
Capitalized interest	1,390		2,229
Total cash paid for capital expenditures	$	112,827	$	175,941

Cash Flows from Financing Activities. The 2020 period includes repayments of $49 million and borrowings of $46 million under the Credit Facility. Borrowings during the 2020 period were used to fund our capital program costs at the beginning of the 2020 period and we were ultimately able to reduce outstanding borrowings due to the suspension of the drilling and completion program and our ability to generate positive cash from operating activities. The 2019 period includes borrowings of $32 million and repayments of $13 million under the Credit Facility which were used to fund a portion of the capital program during that period. We also paid less than $0.1 million and $2.5 million of debt issue costs in the 2020 and 2019 periods, respectively, in connection with amendments to the Credit Facility.

Capitalization

The following table summarizes our total capitalization as of the dates presented:


	June 30,			December 31,
	2020			2019
Credit facility	$	359,400		$	362,400
Second lien term loan, net	193,834			192,628
Total debt, net	553,234			555,028
Shareholders’ equity	590,539			520,745
	$	1,143,773		$	1,075,773
Debt as a % of total capitalization	48		%	52		%

Credit Facility. The Seventh Amendment, which became effective on April 30, 2020, provides a $1.0 billion revolving commitment and initially provided for a $400 million borrowing base, including a $25 million sublimit for the issuance of letters of credit. The borrowing base decreased to $375 million in accordance with the terms of the Seventh Amendment effective July 1, 2020 and, effective October 1, 2020, availability under the Credit Facility is further limited to a maximum of $350 million until the redetermination of the borrowing base in Fall 2021. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and October of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working capital. We had $0.4 million in letters of credit outstanding as of June 30, 2020 and December 31, 2019.

The Credit Facility is scheduled to mature in May 2024; provided that in June 2022, unless we have either extended the maturity date of our $200 million Second Lien Credit Agreement dated as of September 29, 2017, or the Second Lien Facility, to a date that is at least 91 days after May 7, 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will be June 30, 2022.

Eurodollar, including LIBOR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As of June 30, 2020, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.43%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by us and all of our subsidiaries, or the Guarantor Subsidiaries. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on our ability or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets.

Second Lien Facility. On September 29, 2017, we entered into the Second Lien Facility. The maturity date under the Second Lien Facility is September 29, 2022.

The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate, with a floor of 1.00%, plus an applicable margin of 7.00%. Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.89%. As of June 30, 2020, the actual interest rate on outstanding borrowings under the Second Lien Facility was 8.00%. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our election and is computed on the basis of a year of 360 days. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): 101% of the amount being prepaid through September 2020; and thereafter, no premium. The Second Lien Facility also provides for a 101% prepayment premium in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility through September 2020, but no prepayment premium thereafter.

Covenant Compliance. The Credit Facility requires us to maintain (1) a minimum current ratio of 1.00 to 1.00 and (2) a maximum leverage ratio of 3.50 to 1.00, both as defined in the Credit Facility.

The Credit Facility and Second Lien Facility also contain customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, transactions with affiliates, and other customary covenants. In addition, the Credit Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million.

The Credit Facility and Second Lien Facility contain customary events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility and Second Lien Facility, as applicable, the lenders thereto may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility and Second Lien Facility.

As of June 30, 2020, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.

Reference Rate Reform. In July 2017, the U.K.’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility and Second Lien Facility are contractually subject to LIBOR rates and both have terms that extend beyond 2021. The Seventh Amendment anticipates the phase out of LIBOR and provides for the consideration of other internationally recognized alternative rates at that time. We have not yet pursued any technical amendment or other contractual alternative to address this matter with respect to the Second Lien Facility as well as certain LIBOR-based interest rate swaps that we entered into in 2020. We are continuing to evaluate the potential impact of the eventual replacement of the LIBOR interest rate.

Results of Operations

Presentation of Financial Information and Changes in Accounting Principles

Adoption of New Accounting Standards

As discussed in further detail in Notes 2 and 4 to the Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements,” we have adopted the Financial Accounting Standards Board’s, or FASB, Accounting Standards Update, or ASU, Measurement of Credit Losses on Financial Instruments, or ASU 2016–13, effective January 1, 2020. We adopted ASU 2016–13 utilizing the optional cumulative effect transition approach. As a result of the adoption of 2016–13, certain amounts included in the caption Other revenues, net are not comparable between the 2020 and 2019 periods; however, we do not believe that such differences are material.

Year over Year Analysis of Operating and Financial Results

Production

The following tables set forth a summary of our total and average daily production volumes by product for the periods presented:


	Total Production					Average Daily Production
			2020 vs. 2019			2020 vs. 2019
	Three Months Ended June 30,			Favorable	Three Months Ended June 30,		Favorable
	2020	2019	(Unfavorable)	2020	2019	(Unfavorable)
Crude oil (MBbl and BOPD)	1,719	1,821	(102)	18,888	20,007	(1,119)
NGLs (MBbl and BOPD)	303	389	(86)	3,329	4,272	(943)
Natural gas (MMcf and MMcfpd)	1,311	1,947	(636)	14	21	(7)
Total (MBOE and BOEPD)	2,240	2,534	(294)	24,617	27,845	(3,228)









			2020 vs. 2019			2020 vs. 2019
	Six Months Ended June 30,			Favorable	Six Months Ended June 30,		Favorable
	2020	2019	(Unfavorable)	2020	2019	(Unfavorable)
Crude oil (MBbl and BOPD)	3,599	3,473	126	19,777	19,185	592
NGLs (MBbl and BOPD)	610	704	(94)	3,352	3,890	(538)
Natural gas (MMcf and MMcfpd)	2,784	3,478	(694)	15	19	(4)
Total (MBOE and BOEPD)	4,674	4,756	(83)	25,679	26,278	(599)

Total production decreased 12 percent and two percent during the three and six month periods in 2020, respectively, due primarily to fewer wells turned to sales in the second half of 2019 through the second quarter of 2020 when compared to the corresponding periods in the second half of 2018 through the second quarter of 2019. Crude oil production decreased six percent during the three month period in 2020 when compared to the corresponding period in 2019 due primarily to the suspension of the drilling and completion program in April 2020 and a brief period in well shut-ins in April and May of 2020. While overall production was lower in the six-month period in 2020, crude oil production actually increased four percent compared to the corresponding period in 2019 due to a shift in development focus to the oilier north and eastern portions of our acreage holdings. Both the three and six-month periods in 2020 also experienced natural production declines from our more mature wells.

Approximately 77 percent of total production during the three and six-month month periods in 2020 was attributable to crude oil when compared to approximately 72 percent and 73 percent during the corresponding periods in 2019. The increase in the crude oil composition of total production was due primarily to a shift in development plans that began in the second half of 2019 with less emphasis in the southeastern portion of our acreage holdings which have historically higher gas content.

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product for the periods presented:


	Total Product Revenues										Product Revenues per Unit of Volume
					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Three Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
							($ per unit of volume)
Crude oil	$	41,197	$	114,031	$	(72,834)	$	23.97	$	62.63	$	(38.66)
NGLs	1,578		3,502		(1,924)		$	5.21	$	9.01	$	(3.80)
Natural gas	2,020		5,290		(3,270)		$	1.54	$	2.72	$	(1.18)
Total	$	44,795	$	122,823	$	(78,028)	$	20.00	$	48.47	$	(28.47)









					2020 vs. 2019						2020 vs. 2019
	Six Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
							($ per unit of volume)
Crude oil	$	127,505	$	208,843	$	(81,338)	$	35.42	$	60.14	$	(24.72)
NGLs	3,471		9,050		(5,579)		$	5.69	$	12.85	$	(7.16)
Natural gas	4,710		9,567		(4,857)		$	1.69	$	2.75	$	(1.06)
Total	$	135,686	$	227,460	$	(91,774)	$	29.03	$	47.82	$	(18.79)

The following table provides an analysis of the changes in our revenues for the periods presented:


	Three Months Ended June 30, 2020 vs. 2019										Six Months Ended June 30, 2020 vs. 2019
	Revenue Variance Due to										Revenue Variance Due to
	Volume		Price		Total		Volume		Price		Total
Crude oil	$	(6,374)	$	(66,460)	$	(72,834)	$	7,626	$	(88,964)	$	(81,338)
NGLs	(773)		(1,151)		(1,924)		(1,207)		(4,372)		(5,579)
Natural gas	(1,730)		(1,540)		(3,270)		(1,908)		(2,949)		(4,857)
	$	(8,877)	$	(69,151)	$	(78,028)	$	4,511	$	(96,285)	$	(91,774)

Our product revenues during the three and six month periods in 2020 decreased compared to the corresponding periods in 2019 due primarily to 62 percent and six percent lower crude oil prices and volume, respectively, in the three month period in 2020 and 41 percent lower crude oil prices partially offset by four percent higher volume in the six month period in 2020. NGL revenues declined in the three and six month periods in 2020 due to substantially lower pricing (42 percent and 56 percent) and 22 percent and 13 percent lower volumes, respectively. Lower natural gas revenues were primarily attributable to 43 percent and 38 percent lower pricing and 33 percent and 20 percent lower volume, respectively, during the three month and six month periods in 2020. Total crude oil revenues were approximately 92 percent and 94 percent of our total product revenues during the three and six month periods in 2020 as compared to 93 percent and 92 percent during the three and six month periods in 2019.

Realized Differentials

The following table reconciles our realized price differentials from weighted-average NYMEX-quoted prices for WTI crude oil for the periods presented:


							2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,					Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Realized crude oil prices per barrel	$	23.97	$	62.63	$	(38.66)	$	35.42	$	60.14	$	(24.72)
Weighted-average WTI prices	28.00		59.91		(31.91)		36.82		57.45		(20.63)
Realized differential to WTI	$	(4.03)	$	2.72	$	(6.75)	$	(1.40)	$	2.69	$	(4.09)

The adverse impact of COVID-19 and disruptions in the global energy markets exacerbated a declining trend in realized prices that effectively eliminated a premium margin to the NYMEX WTI index price for crude oil in the three and six month periods in of 2020 compared to the corresponding period in 2019. Historically, we had realized premiums to NYMEX WTI index pricing as the majority of our production is sold based on Light Louisiana Sweet, or LLS, or Magellan East Houston, or MEH, pricing.

Effects of Derivatives

The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for realized derivative settlements, for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Crude oil revenues, as reported	$	41,197	$	114,031	$	(72,834)	$	127,505	$	208,843	$	(81,338)
Derivative settlements, net	45,390		(6,585)		51,975		60,917		(8,273)		69,190
	$	86,587	$	107,446	$	(20,859)	$	188,422	$	200,570	$	(12,148)

Crude oil prices per Bbl	$	23.97	$	62.63	$	(38.66)	$	35.42	$	60.14	$	(24.72)
Derivative settlements per Bbl	26.40		(3.62)		30.02		16.92		(2.38)		19.30
	$	50.37	$	59.02	$	(8.64)	$	52.34	$	57.76	$	(5.42)

Natural gas revenues, as reported	$	2,020	$	5,290	$	(3,270)	$	4,710	$	9,567	$	(4,857)
Derivative settlements, net	$	332	$	—	332		$	436	$	—	436
	$	2,352	$	5,290	$	(2,938)	$	5,146	$	9,567	$	(4,421)

Natural gas prices per Mcf	$	1.54	$	2.72	$	(1.18)	$	1.69	$	2.75	$	(1.06)
Derivative settlements per Mcf	$	0.25	$	—	0.25		$	0.16	$	—	0.16
	$	1.79	$	2.72	$	(0.93)	$	1.85	$	2.75	$	(0.90)

Gain on Sales of Assets

We recognize gains and losses on the sale or disposition of assets other than our oil and gas properties upon the completion of the underlying transactions. The following table sets forth the total net gains and losses recognized for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Gain on sales of assets, net	$	8	$	16	$	(8)	$	14	$	41	$	(27)

There were insignificant net gains and losses recognized during the three and six month periods in 2020 and 2019 primarily attributable to the disposition of certain support equipment, tubular inventory and well materials.

Other Revenues, net

Other revenues, net, includes fees for marketing and water disposal services that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our current operations. In addition, charges attributable to credit losses associated with our trade and joint venture partner receivables are included in this caption as a contra-revenue item.

The following table sets forth the total other revenues, net recognized for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Other revenues, net	$	679	$	(72)	$	751	$	1,161	$	494	$	667

Other revenues, net increased during the three and six month periods in 2020 from the corresponding periods in 2019 due primarily to $0.8 million of maintenance costs incurred during the second quarter of 2019 at our water disposal facilities. Water disposal fees were $0.6 million and $1.0 million for the three and six month periods in 2020, respectively, and $0.7 million and $1.2 million for the three and six month periods in 2019.In addition, our marketing fees also declined in the 2020 periods due primarily to lower overall production volume and related marketing activities. Finally, the 2020 periods include credit loss charges that were not incurred in the comparable periods in 2019.

Lease Operating Expenses

LOE includes costs that we incur to operate our producing wells and field operations. The most significant costs include compression and gas-lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies, among others.

The following table sets forth our LOE for the periods presented:


					2020 vs. 2019							2020 vs. 2019
	Three Months Ended June 30,							Favorable		Six Months Ended June 30,					Favorable
	2020		2019		(Unfavorable)			2020		2019		(Unfavorable)
Lease operating	$	9,094	$	10,362	$	1,268		$	19,626	$	21,366	$	1,740
Per unit of production ($ per BOE)	$	4.06	$	4.09	$	0.03		$	4.20	$	4.49	$	0.29
% change per unit of production					0.7		%					6.5		%

LOE decreased on an absolute and per unit basis during the three and six month periods in 2020 when compared to the corresponding periods in 2019. The absolute decrease was due primarily to lower production in the 2020 periods primarily resulting in lower overall compression and repairs and maintenance costs including that attributable to wells that were acquired from other operators in recent years. In addition, we experienced an overall higher level of efficiency attributable to a combination of cost-containment efforts and the application of operational improvements. These reductions were partially offset by higher water disposal costs associated with protective measures from offset stimulation activities in the three and six month periods in 2020.

Gathering, Processing and Transportation

GPT expense includes costs that we incur to gather and aggregate our crude oil, NGL and natural gas production from our wells and deliver them via pipeline or truck to a central delivery point, downstream pipelines or processing plants, and blend or process, as necessary, depending upon the type of production and the specific contractual arrangements that we have with the applicable midstream operators. In addition, GPT expense includes short-term rental charges for crude oil storage tanks.

The following table sets forth our GPT expense for the periods presented:


					2020 vs. 2019							2020 vs. 2019
	Three Months Ended June 30,							Favorable		Six Months Ended June 30,					Favorable
	2020		2019		(Unfavorable)			2020		2019		(Unfavorable)
Gathering, processing and transportation	$	5,593	$	6,408	$	815		$	11,037	$	10,337	$	(700)
Per unit of production ($ per BOE)	$	2.50	$	2.53	$	0.03		$	2.36	$	2.17	$	(0.19)
% change per unit of production					1.2		%					(8.8)		%

While GPT expense declined on an absolute basis and remained relatively flat on a per unit basis during the three month period in 2020 as compared to the corresponding period in 2019, we experienced an increase on an absolute and per unit basis during the six month period in 2020 when compared to the corresponding period in 2019 due primarily to a scheduled rate increase that became effective August 1, 2019, for crude oil gathering services. This was partially offset by a shift in the mix of crude oil production sold at the wellhead with no corresponding GPT expense subsequent to the achievement of required minimum crude oil volumes transported by pipeline. In addition, both the three and six month periods in 2020 includes short-term rental charges that we incurred to temporarily store a portion of our crude oil production.

Production and Ad Valorem Taxes

Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil, NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties, in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on a published index price.

The following table sets forth our production and ad valorem taxes for the periods presented:


							2020 vs. 2019								2020 vs. 2019
	Three Months Ended June 30,								Favorable			Six Months Ended June 30,					Favorable
	2020			2019			(Unfavorable)		2020			2019			(Unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	1,540		$	5,626		$	4,086	$	5,618		$	10,556		$	4,938
Ad valorem taxes	1,090			1,953			863		3,166			2,715			(451)
	$	2,630		$	7,579		$	4,949	$	8,784		$	13,271		$	4,487
Per unit production ($ per BOE)	$	1.17		$	2.99		$	1.82	$	1.88		$	2.79		$	0.91
Production/severance tax rate as a percent of product revenues	3.4		%	4.6		%			4.1		%	4.6		%

Production taxes decreased on an absolute basis and per unit basis during the three and six month periods in 2020 when compared to the corresponding periods in 2019 due primarily to decreases in aggregate commodity sales prices of 59 percent and 39 percent in the 2020 periods. In addition, regulatory certification was recently received resulting the reclassification of certain wells from crude oil to high cost gas which resulted in severance tax savings being realized in the three month period in 2020. Beginning in the second quarter of 2020, we decreased the accruals for ad valorem taxes based on our most recent estimates for assessments which reflects the recent substantial decline in commodity prices. Prior to the second quarter of 2020, our accruals for ad valorem taxes increased substantially beginning in the second quarter of 2019 due to higher commodity-price based valuation assessments experienced in the 2018 and 2019 annual assessment periods, reflective of indicative prices published for 2019, and the effects of growing our assessable property base and increased working interests from acquisition activity.

General and Administrative

Our G&A expenses include employee compensation, benefits and other related costs for our corporate management and governance functions, rent and occupancy costs for our corporate facilities, insurance, and professional fees and consulting costs supporting various corporate-level functions, among others. In order to facilitate a meaningful discussion and analysis of our results of operations with respect to G&A expenses, we have disaggregated certain costs into three components as presented in the table below. Primary G&A encompasses all G&A costs except share-based compensation and certain significant special charges that are generally attributable to material stand-alone transactions or corporate actions that are not otherwise in the normal course.

The following table sets forth the components of our G&A for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Primary G&A	$	7,035	$	5,139	$	(1,896)	$	13,409	$	10,442	$	(2,967)
Share-based compensation	951		1,017		66		1,807		2,055		248
Significant special charges:
Acquisition, divestiture and strategic transaction costs	—		76		76		—		800		800


Total G&A	$	7,986	$	6,232	$	(1,754)	$	15,216	$	13,297	$	(1,919)
Per unit of production ($ per BOE)	$	3.56	$	2.46	$	(1.10)	$	3.26	$	2.80	$	(0.46)
Per unit of production excluding share-based compensation and other significant special charges identified above ($ per BOE)	$	3.14	$	2.03	$	(1.11)	$	2.87	$	2.20	$	(0.67)

Our primary G&A expenses increased on an absolute and per unit basis during the three and six month periods in 2020 compared to the corresponding periods in 2019. The absolute increases are due primarily to the effects of higher payroll, benefits and support costs, including information technology, attributable to a higher overall employee headcount in the 2020 periods and a lower level of capitalized labor attributable to the suspension of our drilling and completion program in the 2020 periods. In addition, we incurred higher consulting costs and professional fees in the 2020 period. These increases were partially offset by lower incentive compensation accruals and the absence of cost-of-living and similar adjustments to salaries and wages in the 2020 periods. The increase in per unit costs was exacerbated by the effect of lower overall production volume in the 2020 periods.

Share-based compensation charges during the periods presented are attributable to the amortization of compensation cost associated with the grants of time-vested restricted stock units, or RSUs, and performance-based restricted stock units, or PRSUs. The grants of RSUs and PRSUs are described in greater detail in Note 14 to the Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements.” A substantial portion of the share-based compensation expense is

attributable to the RSU and PRSU grants made in the normal course in March of 2020 and January of 2017. The remainder is attributable to grants of RSUs and PRSUs to certain employees upon their hiring or as a result of promotion in 2018 and 2019. All of our share-based compensation represents non-cash expenses.

During the first half of 2019, we incurred consulting and other costs, including legal and other professional fees, primarily associated with a merger transaction which was mutually terminated by us and the counterparty in March 2019.

Depreciation, Depletion and Amortization

DD&A expense includes charges for the allocation of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our asset retirement obligations.

The following table sets forth total and per unit costs for DD&A for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
DD&A expense	$	37,135	$	44,298	$	7,163	$	77,853	$	83,168	$	5,315
DD&A rate ($ per BOE)	$	16.58	$	17.48	$	0.90	$	16.66	$	17.49	$	0.83

DD&A decreased on an absolute and a per unit basis during the three and six month periods in 2020 when compared to the corresponding periods in 2019. Lower production volume provided for decreases of $5.1 million and $1.5 million and lower DD&A rates resulted in decreases of $2.0 million and $3.9 million in the 2020 periods, respectively. The lower DD&A rates in the 2020 periods are primarily attributable to the effect of adding additional reserves in the fourth quarter of 2019 partially offset by associated costs added to the full cost pool.

Impairment of Oil and Gas Properties

We assess our oil and gas properties on a quarterly basis based on the results of a Ceiling Test in accordance with the full cost method of accounting for oil and gas properties.


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Impairment of oil and gas properties	$	35,509	$	—	$	(35,509)	$	35,509	$	—	$	(35,509)

During the three and six months ended June 30, 2020, we recorded an impairment of our oil and gas properties of $35.5 million as a result of a decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by our Ceiling Test under the full cost method of accounting for oil and gas properties.

Interest Expense

Interest expense includes charges for outstanding borrowings under the Credit Facility and the Second Lien Facility, derived from internationally-recognized interest rates with a premium based on our credit profile and the level of credit outstanding. In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for utilization and letters of credit. Also included is the accretion of original issue discount on the Second Lien Facility and the amortization of costs capitalized attributable to the Credit Facility and the Second Lien Facility. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage.

The following table summarizes the components of our interest expense for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Interest on borrowings and related fees	$	7,524	$	9,304	$	1,780	$	15,569	$	19,015	$	3,446
Accretion of original issue discount	201		183		(18)		397		363		(34)
Amortization of debt issuance costs	1,513		644		(869)		2,140		1,385		(755)
Capitalized interest	(702)		(1,075)		(373)		(1,390)		(2,229)		(839)
	$	8,536	$	9,056	$	520	$	16,716	$	18,534	$	1,818

Interest expense decreased during the three and six month periods in 2020 as compared to the corresponding periods in 2019 due primarily to the effect of lower interest rates partially offset by higher outstanding balances under the Credit Facility. The weighted-average balances under the Credit Facility were higher in the 2020 periods compared to the 2019 periods by approximately $41 million and $49 million while the weighted-average interest rates were lower during the same periods by 151 basis points and 190 basis points, respectively. The accretion of original issue discount is entirely attributable to the Second Lien Facility and the amortization of debt issuance costs includes amounts attributable to both the Credit Facility and Second Lien Facility. We wrote off approximately $1 million of debt issuance costs associated with the Credit Facility in the second

quarter of 2020 commensurate with the reduction in the borrowing base. We capitalized a smaller portion of interest during the 2020 periods as we maintained a smaller portion of unproved property as compared to the corresponding periods in 2019.

Derivatives

The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our hedged commodity prices and interest rate swaps.

The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio and interest rate swaps for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Commodity derivative gains (losses)	$	(33,473)	$	13,603	$	(47,076)	$	124,329	$	(54,414)	$	178,743
Interest rate swap gains (losses)	(876)		—		(876)		(7,559)		—		(7,559)
	$	(34,349)	$	13,603	$	(47,952)	$	116,770	$	(54,414)	$	171,184

In the six month period in 2020, commodity prices collapsed dramatically due primarily to the economic slowdown associated with the COVID-19 health crisis and the disruptions in the global energy markets. Accordingly, we substantially expanded our commodity hedging program and actively added put hedge contracts that allowed us to benefit from falling prices primarily in the earlier portion of the second quarter of 2020. Realized settlement receipts for crude oil and natural gas derivatives were $45.7 million and $61.4 million during the three and six month periods in 2020 as compared to the realized settlement payments for crude oil of $6.6 million and $8.3 million in the three and six month periods in 2019.

We also began hedging a portion of our exposure to variable interest rates associated with our Credit Facility and Second Lien Facility in 2020. For the three and six month periods in 2020, we paid $0.4 million of net settlements from our interest rate swaps as the benchmark rate declined relative to our weighted-average hedged rate and we recognized mark-to-market losses as well.

Other, net

Other, net includes interest income, non-service costs associated with our retiree benefit plans and miscellaneous items of income and expense that are not directly associated with our current operations, including certain recoveries and write-offs attributable to prior years and properties that have been divested.

The following table sets forth the other income (expense), net recognized for the periods presented:


					2020 vs. 2019						2020 vs. 2019
	Three Months Ended June 30,						Favorable		Six Months Ended June 30,				Favorable
	2020		2019		(Unfavorable)		2020		2019		(Unfavorable)
Other, net	$	(55)	$	8	$	(63)	$	(63)	$	114	$	(177)

Other, net income (expense) decreased during the three and six month periods in 2020 as compared to the corresponding periods in 2019 due primarily to the recovery in the 2019 six month period of sales and use taxes attributable to previously divested properties. Each of the periods in 2020 and 2019 includes comparable charges of less than $0.1 million associated with our retiree benefit plans.

Income Taxes

Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarily Texas, or otherwise have continuing involvement.

The following table summarizes our income tax expense for the periods presented:


							2020 vs. 2019								2020 vs. 2019
	Three Months Ended June 30,								Favorable			Six Months Ended June 30,					Favorable
	2020			2019			(Unfavorable)		2020			2019			(Unfavorable)
Income tax (expense) benefit	$	690		$	(818)		$	1,508	$	(448)		$	(794)		$	346
Effective tax rate	0.7		%	1.6		%			0.7		%	5.8		%

We recognized a federal and state income tax expense for the six months ended June 30, 2020 at the blended rate of 21.6%. The federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.7%, which is fully attributable to the State of Texas. The provision also reflects a reclassification of $1.2 million from deferred tax assets for our remaining refundable alternative minimum tax, or AMT, credit carryforwards, that were accelerated due to certain income tax provisions provided in the CARES Act. In June 2020, we received a refund of $2.5 million for the aforementioned AMT credit carryforwards. Our net deferred income tax liability

balance of $3.0 million as of June 30, 2020 is fully attributable to the State of Texas and primarily related to property and equipment.

Off Balance Sheet Arrangements

As of June 30, 2020, we had no off-balance sheet arrangements other than information technology licensing, service agreements, in-kind commodity recovery arrangements for imbalances and letters of credit, all of which are customary in our business.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America, or GAAP, requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2019.

As described in this Quarterly Report on Form 10-Q as well as the Critical Accounting Estimates disclosures in the Annual Report on Form 10-K, we apply the full cost method to account for our oil and gas properties. At the end of each quarterly reporting period, we perform a Ceiling Test in order to determine if our oil and gas properties have been impaired. For purposes of the Ceiling Test, estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

As of June 30, 2020, the carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test by $35.5 million which resulted in our recording an impairment charge for the period then ended. Because the Ceiling Test utilizes commodity prices based on a trailing twelve month average, it does not fully reflect the substantial decline in commodity prices due to the economic impact of the COVID-19 health crisis and the ongoing disruption in global energy markets. If current commodity prices continue at these levels or decline further, it is likely that we will experience an additional impairment in the carrying value of our oil and gas properties during the second half of 2020.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.

Interest Rate Risk

All of our long-term debt instruments are subject to variable interest rates. As of June 30, 2020, we had borrowings of $359.4 million under the Credit Facility and $200 million under the Second Lien Facility at interest rates of 3.43% and 8.00%, respectively. Assuming a constant borrowing level under the Credit Facility and Second Lien Facility, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in aggregate interest payments of approximately $6.0 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as swaps) to seek to mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe to be of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of crude oil. We have not typically entered into derivative instruments with respect to NGLs, although we may do so in the future.

As of June 30, 2020, our commodity derivative portfolio was in a net assets position. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions.

During the six months ended June 30, 2020, we reported net commodity derivative gains of $116.8 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations

could be significant in a volatile pricing environment. See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

The following table sets forth our commodity derivative positions as of June 30, 2020:


	3Q2020		4Q2020		1Q2021		2Q2021		3Q2021		4Q2021
NYMEX WTI Crude Swaps
Average Volume Per Day (barrels)	11,457		9,804		6,667		6,593
Weighted Average Swap Price ($/barrel)	$	51.17	$	55.18	$	48.73	$	48.73
NYMEX WTI Purchased Puts/Sold Calls
Average Volume Per Day (barrels)	4,043		2,000		3,333		3,297		3,261		3,261
Weighted Average Purchased Put Price ($/barrel)	$	52.70	$	48.00	$	47.50	$	47.50	$	40.00	$	40.00
Weighted Average Sold Call ($/barrel)	$	58.26	$	57.10	$	51.51	$	51.51	$	50.00	$	50.00
NYMEX WTI Purchased Puts
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	55.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	674
Weighted Average Purchased Put ($/barrel)	$	48.00
Weighted Average Premium ($/barrel)	$	0.06
Average Volume Per Day (barrels)	2,174
Weighted Average Purchased Put ($/barrel)	$	37.00
Weighted Average Deferred Premium ($/barrel)	$	1.23
Average Volume Per Day (barrels)	2,717
Weighted Average Purchased Put ($/barrel)	$	30.00
Weighted Average Deferred Premium ($/barrel)	$	3.63
Average Volume Per Day (barrels)					2,500		2,473
Weighted Average Purchased Put ($/barrel)					$	36.00	$	36.00
Weighted Average Premium ($/barrel)					$	4.50	$	4.50
NYMEX WTI Put Spread
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	39.00
Weighted Average Put Spread Sold Put ($/barrel)	$	32.00
Weighted Average Deferred Premium ($/barrel)	$	3.25
Average Volume Per Day (barrels)	2,174
Weighted Average Put Spread Purchased Put ($/barrel)	$	30.00
Weighted Average Put Spread Sold Put ($/barrel)	$	20.00
Weighted Average Deferred Premium ($/barrel)	$	2.45
NYMEX WTI Sold Puts
Average Volume Per Day (barrels)			5,087		10,833		10,714		3,261		3,261
Weighted Average Sold Put Price ($/barrel)			$	43.50	$	37.00	$	37.00	$	35.00	$	35.00
MEH Crude Swaps
Average Volume Per Day (barrels)	2,000		2,000
Weighted Average Swap Price ($/barrel)	$	61.03	$	61.03
MEH-NYMEX WTI Crude Basis Swaps
Average Volume Per Day (barrels)	10,870
Weighted Average Swap Price ($/barrel)	$	1.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (barrels)	10,870
Weighted Average Swap Price ($/barrel)	$	(0.45)
NYMEX HH Purchased Puts/Sold Calls
Average Volume Per Day (MMBtus)	12,804		12,804		3,333		3,297		3,261		3,261
Weighted Average Purchased Put ($/MMBtu)	$	2.00	$	2.00	$	2.50	$	2.50	$	2.50	$	2.50
Weighted Average Sold Call ($/MMBtu)	$	2.21	$	2.21	$	2.85	$	2.85	$	2.85	$	2.85

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil and natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.


	Change of 10% per Bbl of Crude Oil ($ in millions)
	Increase		Decrease
Effect on the fair value of crude oil derivatives ¹	$	(13.1)	$	12.5
Effect of crude oil price changes for the remainder of 2020 on operating income, excluding derivatives ²	$	12.6	$	(12.6)

_____________________________

¹ Based on derivatives outstanding as of June 30, 2020.

²These sensitivities are subject to significant change.

Item 4. Controls and Procedures.

(a) Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2020. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 2020, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the quarter ended June 30, 2020, there were no changes to our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are not aware of any material pending legal or governmental proceedings against us, any material proceedings by governmental officials against us that are pending or contemplated to be brought against us and no such proceedings have been terminated during the period covered by this quarterly report on Form 10-Q. See Note 12 to our Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements” for additional information regarding our legal and regulatory matters.

Item 1A. Risk Factors.

There have been no material changes to the risk factors disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2019 and Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020.

Item 5. Other Information.

None.

Item 6. Exhibits.


(10.1)			Borrowing Base Redetermination Agreement and Amendment No. 7 to Credit Agreement, dated as of April 30, 2020, among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto and Wells Fargo Bank National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on May 6, 2020).

(10.2) *			Amendment No. 1 to the Penn Virginia Corporation 2017 Special Severance Plan dated as of April 21, 2020.

(31.1) *			Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2) *			Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1) †			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.2) †			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(101.INS) *			Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

(101.SCH) *			Inline XBRL Taxonomy Extension Schema Document

(101.CAL) *			Inline XBRL Taxonomy Extension Calculation Linkbase Document

(101.DEF) *			Inline XBRL Taxonomy Extension Definition Linkbase Document

(101.LAB) *			Inline XBRL Taxonomy Extension Label Linkbase Document

(101.PRE) *			Inline XBRL Taxonomy Extension Presentation Linkbase Document

(104) *			The cover page of Penn Virginia Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, formatted in Inline XBRL (included within the Exhibit 101 attachments).

_____________________________

* Filed herewith.

† Furnished herewith.

SIGNATURES

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.

PENN VIRGINIA CORPORATION

August 7, 2020

By:

/s/ RUSSELL T KELLEY, JR.

Russell T Kelley, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

August 7, 2020

By:

/s/ TAMMY L. HINKLE

Tammy L. Hinkle

Vice President and Controller

(Principal Accounting Officer)