Document

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 September 30, 2019



☐	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	The 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 November 1, 2019, 15,123,128 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended September 30, 2019

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	9
	5. Derivative Instruments	10
	6. Property and Equipment	11
	7. Long-Term Debt	12
	8. Income Taxes	13
	9. Leases	14
	10. Additional Balance Sheet Detail	16
	11. Fair Value Measurements	16
	12. Commitments and Contingencies	17
	13. Shareholders’ Equity	18
	14. Share-Based Compensation and Other Benefit Plans	19
	15. Interest Expense	20
	16. Earnings per Share	20
Forward-Looking Statements		21
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Overview and Executive Summary	22
	Key Developments	24
	Financial Condition	25
	Results of Operations	29
	Off Balance Sheet Arrangements	36
	Critical Accounting Estimates	36
3.	Quantitative and Qualitative Disclosures About Market Risk.	37
4.	Controls and Procedures.	38
Part II - Other Information
1.	Legal Proceedings.	39
1A.	Risk Factors.	39
5.	Other Information	39
6.	Exhibits.	39
Signatures		40

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues
Crude oil	$	110,618		$	117,059		$	319,461		$	290,033
Natural gas liquids	3,546			5,976			12,596			14,455
Natural gas	4,215			3,768			13,782			10,470
Gain on sales of assets, net	77			2			118			81
Other revenues, net	848			380			1,342			937
Total revenues	119,304			127,185			347,299			315,976
Operating expenses
Lease operating	11,868			9,898			33,234			25,924
Gathering, processing and transportation	6,600			4,928			16,937			12,861
Production and ad valorem taxes	7,401			7,152			20,672			17,039
General and administrative	6,876			6,155			20,173			17,948
Depreciation, depletion and amortization	46,519			35,016			129,687			88,370
Total operating expenses	79,264			63,149			220,703			162,142
Operating income	40,040			64,036			126,596			153,834
Other income (expense)
Interest expense	(8,736		)	(7,322		)	(27,270		)	(18,073		)
Derivatives	24,248			(40,689		)	(30,166		)	(111,725		)
Other, net	(248		)	241			(134		)	167
Income before income taxes	55,304			16,266			69,026			24,203
Income tax (expense) benefit	(942		)	10			(1,736		)	(153		)
Net income	$	54,362		$	16,276		$	67,290		$	24,050
Net income per share:
Basic	$	3.60		$	1.08		$	4.45		$	1.60
Diluted	$	3.59		$	1.06		$	4.44		$	1.57

Weighted average shares outstanding – basic	15,110			15,062			15,105			15,054
Weighted average shares outstanding – diluted	15,160			15,344			15,165			15,278

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019			2018
Net income	$	54,362	$	16,276	$	67,290		$	24,050
Other comprehensive income:
Change in pension and postretirement obligations, net of tax	—		—		(2		)	—
	—		—		(2		)	—
Comprehensive income	$	54,362	$	16,276	$	67,288		$	24,050

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)



	September 30,		December 31,
	2019		2018
Assets
Current assets
Cash and cash equivalents	$	11,387	$	17,864
Accounts receivable, net of allowance for doubtful accounts	62,300		66,038
Derivative assets	18,214		34,932
Income taxes receivable	3,707		2,471
Other current assets	5,570		5,125
Total current assets	101,178		126,430
Property and equipment, net (full cost method)	1,099,144		927,994
Derivative assets	4,311		10,100
Deferred income taxes	—		1,949
Other assets	7,147		2,481
Total assets	$	1,211,780	$	1,068,954

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	118,975	$	103,700
Derivative liabilities	4,308		991
Total current liabilities	123,283		104,691
Other liabilities	8,359		5,533
Deferred income taxes	1,023		—
Derivative liabilities	12		—
Long-term debt, net	562,445		511,375

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; 15,123,128 and 15,080,594 shares issued as of September 30, 2019 and December 31, 2018, respectively	151		151
Paid-in capital	199,739		197,630
Retained earnings	316,688		249,492
Accumulated other comprehensive income	80		82
Total shareholders’ equity	516,658		447,355
Total liabilities and shareholders’ equity	$	1,211,780	$	1,068,954

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)



	Nine Months Ended September 30,
	2019			2018
Cash flows from operating activities
Net income	$	67,290		$	24,050
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	129,687			88,370
Derivative contracts:
Net losses	30,166			111,725
Cash settlements, net	(4,330		)	(35,191		)
Deferred income tax expense	2,972			153
Gain on sales of assets, net	(118		)	(81		)
Non-cash interest expense	2,544			2,509
Share-based compensation (equity-classified)	3,101			3,472
Other, net	39			38
Changes in operating assets and liabilities, net	12,862			(2,140		)
Net cash provided by operating activities	244,213			192,905

Cash flows from investing activities
Acquisitions, net	(5,956		)	(85,387		)
Capital expenditures	(291,733		)	(323,259		)
Proceeds from sales of assets, net	215			7,989
Net cash used in investing activities	(297,474		)	(400,657		)

Cash flows from financing activities
Proceeds from credit facility borrowings	62,400			205,500
Repayment of credit facility borrowings	(13,000		)	—
Debt issuance costs paid	(2,616		)	(754		)
Net cash provided by financing activities	46,784			204,746
Net decrease in cash and cash equivalents	(6,477		)	(3,006		)
Cash and cash equivalents – beginning of period	17,864			11,017
Cash and cash equivalents – end of period	$	11,387		$	8,011

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	24,721		$	15,174
Reorganization items, net	$	79		$	514
Non-cash investing and financing activities:
Changes in accounts receivable related to acquisitions	$	(152	)	$	(26,631	)
Changes in other assets related to acquisitions	$	—		$	(2,469	)
Changes in accrued liabilities related to acquisitions	$	(504	)	$	(15,099	)
Changes in accrued liabilities related to capital expenditures	$	2,672		$	1,833
Changes in other liabilities for asset retirement obligations related to acquisitions	$	83		$	382

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2019

(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 engaged in 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.


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, 2018. Operating results for the nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019.

Adoption of Recently Issued Accounting Pronouncements

Effective January 1, 2019, we adopted and began applying the relevant guidance provided in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Update (“ASU”) 2016–02, Leases (“ASU 2016–02”) and related amendments to GAAP which, together with ASU 2016–02, represent ASC Topic 842, Leases (“ASC Topic 842”). We adopted ASC Topic 842 using the optional transition approach with a charge to the beginning balance of retained earnings as of January 1, 2019 (see Note 9 for the impact and disclosures associated with the adoption of ASC Topic 842). Comparative periods and related disclosures have not been restated for the application of ASC Topic 842.

Recently Issued Accounting Pronouncements Pending Adoption

In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. We plan to adopt ASU 2016–13 effective January 1, 2020.

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 and Divestitures

Acquisitions

Eagle Ford Working Interests

In August 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 million. Funding for this acquisition was provided by borrowings under our credit agreement (the “Credit Facility”).

Hunt Acquisition

In December 2017, we entered into a purchase and sale agreement with Hunt Oil Company (“Hunt”) to acquire certain oil and gas assets in the Eagle Ford Shale, primarily in Gonzales County, Texas for $86.0 million in cash, subject to adjustments (the “Hunt Acquisition”). The Hunt Acquisition had an effective date of October 1, 2017, and closed on March 1, 2018, at which time we paid cash consideration of $84.4 million. In connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator in which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $13.8 million, which we have reflected as a component of the total net assets acquired. We funded the Hunt Acquisition with borrowings under the Credit Facility.

The final settlement of the Hunt Acquisition occurred in July 2018, at which time an additional $0.2 million of acquisition costs was allocated from certain working capital components and Hunt transferred $1.4 million to us primarily for suspended revenues attributable to the acquired properties.

We incurred a total of $0.5 million of transaction costs for legal, due diligence and other professional fees associated with the Hunt Acquisition, including $0.1 million in 2017 and $0.4 million in the first quarter of 2018. These costs have been recognized as a component of our “General and administrative” (“G&A”) expenses.

We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the final fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt:



Assets
Oil and gas properties - proved	$	82,443
Oil and gas properties - unproved	16,339
Liabilities
Revenue suspense	1,448
Asset retirement obligations	356
Net assets acquired	$	96,978

Cash consideration paid to Hunt, net	$	82,955
Application of working capital adjustments	245
Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate	13,778
Total acquisition costs incurred	$	96,978

Valuation of Acquisitions

The fair values of the oil and gas properties acquired in the transactions referenced above were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future cash flows, (v) the timing of our development plans and (vi) a market-based weighted-average cost of capital. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP.

Impact of Acquisitions on Actual and Pro Forma Results of Operations

The results of operations attributable to the Hunt Acquisition have been included in our Consolidated Financial Statements for the periods after March 1, 2018. As the properties and working interests acquired in connection with the Hunt Acquisition are included within our existing Eagle Ford acreage, it is not practical or meaningful to disclose revenues and earnings unique to those assets for periods beyond those during which they were acquired, as they were fully integrated into our regional operations soon after their acquisition.

The following table presents unaudited summary pro forma financial information for the nine months ended September 30, 2018, assuming the Hunt Acquisition occurred as of January 1, 2018. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt Acquisition had occurred as of this date, or the results of operations for any future periods.



	Nine Months Ended September 30,
	2018
Total revenues	$	321,221
Net income	$	26,162
Net income per share - basic	$	1.74
Net income per share - diluted	$	1.71

Divestitures

Mid-Continent Divestiture

In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $6.0 million in cash, subject to customary adjustments. The sale had an effective date of March 1, 2018 and closed on July 31, 2018, at which time we received net proceeds of $6.2 million. The sale proceeds and de-recognition of certain assets and liabilities were recorded as a reduction of our net oil and gas properties. In November 2018, we paid $0.5 million, including $0.2 million of suspended revenues, to the buyer in connection with the final settlement.

The Mid-Continent properties had asset retirement obligations (“AROs”) of $0.3 million as well as a net working capital deficit attributable to the oil and gas properties of $1.3 million as of July 31, 2018. The net pre-tax operating income attributable to the Mid-Continent assets was $0.2 million and $1.6 million for the three and nine months ended September 30, 2018.

Sales of Undeveloped Acreage, Rights and Other Assets

In February 2018, we sold our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire in 2019. In March 2018, we sold certain undeveloped deep leasehold rights in Oklahoma, and in May 2018, we sold certain pipeline assets in our former Marcellus Shale operating region. We received a combined total of $1.7 million for these leasehold and other assets which were applied as a reduction of our net oil and gas properties.

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:



	September 30,			December 31,
	2019			2018
Customers	$	54,987		$	59,030
Joint interest partners	6,703			6,404
Other	661			640
	62,351			66,074
Less: Allowance for doubtful accounts	(51		)	(36		)
	$	62,300		$	66,038

For the nine months ended September 30, 2019, four customers accounted for $261.4 million, or approximately 76%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2019, were $127.1 million, $62.4 million, $37.3 million and $34.6 million, or 37%, 18%, 11% and 10% of the consolidated total, respectively. As of September 30, 2019 and December 31, 2018, $32.9 million and $37.3 million, or approximately 60% and 63%, of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. For the nine months ended September 30, 2018, three customers accounted for $254.5 million, or approximately 81%, of our consolidated product revenues. The allowance for doubtful accounts is entirely attributable to certain receivables from joint interest partners.


5.	Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to commodity price volatility. Our derivative instruments are not formally designated as hedges in the context of GAAP.

We typically utilize collars and swaps, which are placed with financial institutions that we believe to be acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate (“WTI”), Louisiana Light Sweet (“LLS”) and Magellan East Houston (“MEH”) crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize 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. We are currently unhedged with respect to NGL and natural gas production.

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of September 30, 2019:



		Average	Weighted
		Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2019	Swaps-WTI	11,398	$	55.97	$	2,804	$	—
Fourth quarter 2019	Swaps-LLS	5,000	$	59.17	995		—
Fourth quarter 2019	Swaps-MEH	1,000	$	64.00	131		—
First quarter 2020	Swaps-WTI	9,000	$	55.19	2,942		—
First quarter 2020	Swaps-MEH	2,000	$	61.03	114		—
Second quarter 2020	Swaps-WTI	7,000	$	54.94	3,220		—
Second quarter 2020	Swaps-MEH	2,000	$	61.03	90		—
Third quarter 2020	Swaps-WTI	7,000	$	54.94	3,878		—
Third quarter 2020	Swaps-MEH	2,000	$	61.03	100		—
Fourth quarter 2020	Swaps-WTI	7,000	$	54.94	4,203		—
Fourth quarter 2020	Swaps-MEH	2,000	$	61.03	96		—
Settlements to be paid in subsequent period							368

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
Derivative gains (losses)	$	24,248	$	(40,689	)	$	(30,166	)	$	(111,725	)

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 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:



		September 30, 2019				December 31, 2018
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	18,214	$	4,308	$	34,932	$	991
Commodity contracts	Derivative assets/liabilities – noncurrent	4,311		12		10,100		—
		$	22,525	$	4,320	$	45,032	$	991

As of September 30, 2019, we reported net commodity derivative assets of $18.2 million. The contracts associated with this position are with eight counterparties, 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. 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:



	September 30,			December 31,
	2019			2018
Oil and gas properties:
Proved	$	1,329,116		$	1,037,993
Unproved	67,865			63,484
Total oil and gas properties	1,396,981			1,101,477
Other property and equipment	25,359			20,383
Total properties and equipment	1,422,340			1,121,860
Accumulated depreciation, depletion and amortization	(323,196		)	(193,866		)
	$	1,099,144		$	927,994

Unproved property costs of $67.9 million and $63.5 million have been excluded from amortization as of September 30, 2019 and December 31, 2018, respectively. An additional $3.5 million and $0.3 million of costs, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of September 30, 2019 and December 31, 2018. We transferred $0.2 million and $11.4 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 nine months ended September 30, 2019 and 2018, respectively. We capitalized internal costs of $3.2 million and $2.4 million and interest of $3.2 million and $7.1 million during the nine months ended September 30, 2019 and 2018, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $17.47 and $15.83 for the nine months ended September 30, 2019 and 2018, respectively.


7.	Long-Term Debt

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



	September 30, 2019					December 31, 2018
	Principal			Unamortized Discount and Deferred Issuance Costs ^{1, 2}		Principal			Unamortized Discount and Deferred Issuance Costs ^{1, 2}
Credit facility	$	370,400				$	321,000
Second lien term loan	200,000			$	7,955	200,000			$	9,625
Totals	570,400			$	7,955	521,000			$	9,625
Less: Unamortized discount ²	(2,608		)			(3,159		)
Less: Unamortized deferred issuance costs ^{1, 2}	(5,347		)			(6,466		)
Long-term debt, net	$	562,445				$	511,375

_______________________


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

The Credit Facility provides for a $1.0 billion revolving commitment and $500 million borrowing base and a $25 million sublimit for the issuance of letters of credit. In the nine months ended September 30, 2019, we incurred and capitalized approximately $2.6 million of issue and other costs associated with the Credit Facility. Availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and October of each year. Our fall borrowing base re-determination is currently in process. Additionally, the Credit Facility lenders may, at their discretion, 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 September 30, 2019 and December 31, 2018.

In May 2019, maturity of the Credit Facility was extended to May 2024 from September 2020; 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 (the “Second Lien Facility”) described below to a date that is at least 91 days after the extended maturity date of May 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will mean June 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 0.50% to 1.50%, determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 1.50% to 2.50%, determined based on the average availability 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 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 September 30, 2019, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.07%. Unused commitment fees are charged at a rate of 0.375% to 0.50%, depending upon utilization.

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.

Effective May 2019, 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 4.00 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, 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.

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 September 30, 2019, 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 plus an applicable margin of 7.00%. As of September 30, 2019, the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.05%. 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): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums 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: during years one and two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.

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 September 30, 2019, 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 nine months ended September 30, 2019 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 2.5%, which related to Texas deferred tax expense. The effect of the valuation allowance, as well as a reclassification of $1.2 million from deferred tax assets to the current income tax receivable for refundable alternative minimum tax (“AMT”) credit carryforwards, was to adjust our deferred tax asset to a deferred tax liability position of $1.0 million as of September 30, 2019. We recognized a federal income tax expense for the nine months ended September 30, 2018 at the blended rate of 21.6% which was similarly offset by a valuation allowance against our net deferred tax assets. We recorded an adjustment of $0.2 million to the deferred tax asset related to sequestration of a portion of the aforementioned AMT credit carryforward resulting in an effective tax rate of 0.6%. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, due primarily to cumulative losses.

We had no liability for unrecognized tax benefits as of September 30, 2019. There were no interest and penalty charges recognized during the periods ended September 30, 2019 and 2018. Tax years from 2014 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

Adoption of ASC Topic 842

Effective January 1, 2019, we adopted ASC Topic 842 and have applied the guidance therein to all of our contracts and agreements explicitly identified as leases as well as other contractual arrangements that we have determined to include or otherwise have the characteristics of a lease as defined in ASC Topic 842. As illustrated in the disclosures below, the adoption of ASC Topic 842 resulted in the recognition of certain assets and liabilities on our Condensed Consolidated Balance Sheet and changes in the amounts and timing of lease cost recognition in our Condensed Consolidated Statements of Operations as compared to prior GAAP. We have adopted ASC Topic 842 using the optional transition approach with an adjustment to the beginning balance of retained earnings as of January 1, 2019. Accordingly, our 2019 financial statements are not comparable with respect to leases in effect during all periods prior to January 1, 2019. On January 1, 2019, we recognized operating lease right-of-use (“ROU”) assets of $2.5 million and operating lease obligations of $2.8 million on our Condensed Consolidated Balance Sheet for operating leases in effect on that date. We recorded an immaterial adjustment to the beginning balance of retained earnings as of January 1, 2019 representing the difference between the operating lease ROU assets and operating lease obligations recognized upon adoption net of amounts already included in our liabilities as of December 31, 2018 that were attributable to straight-line lease expense in excess of amounts paid for certain operating leases. We did not identify any finance leases, as defined in ASC Topic 842, upon the date of initial adoption.

Accounting Policies for Leases

We determine if an arrangement is a lease at the inception of the underlying contractual arrangement. Operating leases are included in the captions “Other assets,” “Accounts payable and accrued liabilities” and “Other liabilities” on our Condensed Consolidated Balance Sheets and are identified as ROU assets - operating, Current operating lease obligations and Noncurrent operating lease obligations, respectively, below and in Note 10.

ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to five years, our secured incremental borrowing rate is primarily based on the rates applicable to our Credit Facility.

We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We have elected to apply a practical expedient provided in ASC Topic 842 to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term.

Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we have elected to not include the underlying ROU assets and lease obligations on our Condensed Consolidated Balance Sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables that follow.

Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in the summary below.

Lease Arrangements and Supplemental Disclosures

We have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs and our field compressors. Our primary variable lease includes 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			Nine Months Ended
	September 30, 2019
Operating lease cost	$	208		$	565
Short-term lease cost	9,969			33,024
Variable lease cost	6,777			17,420
Less: Amounts charged as drilling costs ¹	(9,224		)	(30,865		)
Total lease cost recognized in the Condensed Consolidated Statement of Operations ²	$	7,730		$	20,144

___________________


¹	Represents 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.


²	Includes $3.9 million and $8.9 million recognized in Gathering, processing and transportation, $3.6 million and $10.7 million recognized in Lease operating and $0.2 million and $0.6 million recognized in G&A for the three and nine months ended September 30, 2019, respectively.

The following table summarizes supplemental cash flow information related to leases for the nine months ended September 30, 2019:



Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	442
ROU assets obtained in exchange for lease obligations:
Operating leases ¹	$	3,325

___________________

¹Includes $2.5 million recognized upon adoption of ASC Topic 842 and $0.8 million obtained during the nine months ended September 30, 2019.

The following table summarizes supplemental balance sheet information related to leases as of September 30, 2019:



ROU assets - operating leases	$	2,901

Current operating lease obligations	$	858
Noncurrent operating lease obligations	2,389
Total operating lease obligations	$	3,247

Weighted-average remaining lease term
Operating leases	4.3 Years

Weighted-average discount rate
Operating leases	5.97		%

Maturities of operating lease obligations for the years ending December 31,
2019	$	217
2020	847
2021	830
2022	833
2023	833
2024 and thereafter	139
Total undiscounted lease payments	3,699
Less: imputed interest	(452		)
Total operating lease obligations	$	3,247


10.	Additional Balance Sheet Detail

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



	September 30,		December 31,
	2019		2018
Other current assets:
Tubular inventory and well materials	$	3,792	$	4,061
Prepaid expenses	1,778		1,064
	$	5,570	$	5,125
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	4,179	$	2,437
Right-of-use assets – operating leases	2,901		—
Other	67		44
	$	7,147	$	2,481
Accounts payable and accrued liabilities:
Trade accounts payable	$	33,036	$	16,507
Drilling costs	25,105		22,434
Royalties and revenue – related	43,354		51,212
Production, ad valorem and other taxes	7,562		2,418
Compensation – related	5,011		4,489
Interest	675		670
Current operating lease obligations	858		—
Other	3,374		5,970
	$	118,975	$	103,700
Other liabilities:
Asset retirement obligations	$	4,784	$	4,314
Noncurrent operating lease obligations	2,389		—
Defined benefit pension obligations	777		857
Postretirement health care benefit obligations	409		362
	$	8,359	$	5,533


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 September 30, 2019, 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:



	September 30, 2019
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	18,214		$	—	$	18,214		$	—
Commodity derivative assets – noncurrent	$	4,311		$	—	$	4,311		$	—
Liabilities:
Commodity derivative liabilities – current	$	(4,308	)	$	—	$	(4,308	)	$	—
Commodity derivative liabilities – noncurrent	$	(12	)	$	—	$	(12	)	$	—



	December 31, 2018
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	34,932		$	—	$	34,932		$	—
Commodity derivative assets - noncurrent	$	10,100		$	—	$	10,100		$	—
Liabilities:
Commodity derivative liabilities – current	$	(991	)	$	—	$	(991	)	$	—
Commodity derivative liabilities – noncurrent	$	—		$	—	$	—		$	—

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 nine months ended September 30, 2019 and 2018.

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 based on discounted cash flows derived from third-party quoted forward prices for WTI, LLS and MEH crude oil closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a Level 2 input.

Non-Recurring Fair Value Measurements

In addition to the fair value measurements applied with respect to the Hunt Acquisition, as described in Note 3, 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

Gathering and Intermediate Transportation Commitments

We have long-term agreements with Nuevo Dos Gathering and Transportation, LLC (“Nuevo G&T”) and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”), successor to Republic Midstream, LLC and affiliates, to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in South Texas 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.

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.

Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements attributable to the MVC under the gathering and transportation agreement are as follows: $3.2 million for the remainder of 2019, $13.0 million per year for 2020 through 2025, $7.4 million for 2026, $3.8 million per year for 2027 through 2030 and $2.2 million for 2031.

Drilling, Completion and Other Commitments

As of September 30, 2019, we had contractual commitments on a pad-to-pad basis for two drilling rigs. Additionally, we have a one-year agreement, effective January 1, 2019, which can be terminated with 60 days’ notice by either party, to utilize certain frac services, with no minimum commitment.

Legal and Regulatory

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 September 30, 2019, we had a reserve in the amount of $0.3 million included in “Accounts payable and accrued liabilities” for the estimated settlement of disputes with partners regarding certain transactions that occurred in prior years. As of September 30, 2019, we had AROs of approximately $4.8 million attributable to the plugging of abandoned wells.

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 2019 and 2018.



	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
Net income	—		—		54,362			—			54,362
All other changes ²	—		742		—			—			742
Balance as of September 30, 2019	$	151	$	199,739	$	316,688		$	80		$	516,658

_______________________


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 $3.1 million during the nine months ended September 30, 2019. During the nine months ended September 30, 2019, 42,534 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”), 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, 2017	$	150	$	194,123	$	27,366		$	—	$	221,639
Net income	—		—		10,295			—		10,295
Cumulative effect of change in accounting principle ¹	—		—		(2,659		)	—		(2,659		)
All other changes ²	1		988		—			—		989
Balance as of March 31, 2018	$	151	$	195,111	$	35,002		$	—	$	230,264
Net loss	—		—		(2,521		)	—		(2,521		)
All other changes ²	—		869		—			—		869
Balance as of June 30, 2018	$	151	$	195,980	$	32,481		$	—	$	228,612
Net income					16,276					16,276
All other changes ²			1,020							1,020
Balance as of September 30, 2018	$	151	$	197,000	$	48,757		$	—	$	245,908

_______________________


¹	Reflects a write-off for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018, in connection with the adoption of ASC Topic 606, Revenues from Contracts with Customers.

² Includes equity-classified share-based compensation of $3.5 million during the nine months ended September 30, 2018. During the nine months ended September 30, 2018, 53,411 and 1,495 shares of common stock were issued in connection with the vesting of certain RSUs and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively.


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 for share-based compensation awards. A total of 357,147 RSUs and 98,526 PRSUs have been granted to employees and directors as of September 30, 2019.

We recognized $1.0 million and $3.1 million of expense attributable to the RSUs and PRSUs for the three and nine months ended September 30, 2019, respectively, and $1.0 million and $3.5 million for the three and nine months ended September 30, 2018, respectively. Approximately $0.6 million of the expense for the nine months ended September 30, 2018 was attributable to the accelerated vesting of certain awards of our former Executive Chairman upon his retirement. We also paid him $0.3 million for certain transition and support services during this period in connection with his retirement.

A total of 9,707 RSUs were granted during the nine months ended September 30, 2019 with an average grant-date fair value of $30.65. In the nine months ended September 30, 2018, we granted 42,459 RSUs with an average grant-date fair value of $65.96 per RSU. The RSUs are being charged to expense on a straight-line basis over a range of two to five years. In the nine months ended September 30, 2019 and 2018, 42,534 and 53,411 shares were issued upon vesting/settlement of equity awards, net of shares withheld for income taxes, respectively.

No PRSUs were granted during the nine months ended September 30, 2019 or 2018. In the nine months ended September 30, 2018, 1,495 shares were issued upon vesting/settlement of equity awards, net of shares withheld for income taxes. The PRSUs were granted collectively in two to three separate tranches with individual three-year performance periods beginning in January 2017, 2018 and 2019, respectively. 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. 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. Expected volatilities were based on historical volatilities and range from 59.63% to 62.18%. A risk-free rate of interest with a range of 1.44% to 1.51% was utilized, which is equivalent to the yield, as of the measurement date, of the zero-coupon U.S. Treasury bill commensurate with the longest remaining performance measurement period for each tranche. We assumed no payment of dividends during the performance periods.

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 $0.5 million of expense attributable to the 401(k) Plan for the three and nine months ended September 30, 2019, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2018, 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 nine months ended September 30, 2019 and 2018. 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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Interest on borrowings and related fees	$	8,945		$	8,897		$	27,960		$	22,675
Accretion of original issue discount ¹	188			172			551			505
Amortization of debt issuance costs	608			693			1,993			2,004
Capitalized interest	(1,005		)	(2,440		)	(3,234		)	(7,111		)
	$	8,736		$	7,322		$	27,270		$	18,073

___________________


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


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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net income - basic and diluted	$	54,362	$	16,276	$	67,290	$	24,050

Weighted-average shares – basic	15,110		15,062		15,105		15,054
Effect of dilutive securities	50		282		60		224
Weighted-average shares – diluted	15,160		15,344		15,165		15,278

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:


•	risks related to potential and completed acquisitions, including related costs and 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 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;


•	the decline in and volatility of expected and realized commodity prices for oil, natural gas liquids, or NGLs, and natural gas;


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


•	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; 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, 2018.

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. References to “quarters” represent the three months ended September 30, 2019 or 2018, as applicable.

Overview and Executive Summary

We are an independent oil and gas company engaged in 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

Crude oil prices increased moderately throughout the first half of 2019, rising from levels in the upper $40 per barrel range at the beginning of the year and into the lower $60 per barrel range in April and May before falling back to the mid $50 per barrel range by the end of September 2019 due primarily to domestic and global supply and demand and other geopolitical dynamics. While impacting us to a lesser extent, NGL and natural gas pricing has steadily declined from year-end 2018 levels due primarily to excess domestic supply. Collectively, these trends have had a substantial impact on the rate of growth in our product revenues.

Since February 2019, we have contracted for our drilling rigs on a pad-to-pad basis and the day rates charged for these services as well as casing costs have declined through the nine months ended September 30, 2019. In addition, costs associated with our dedicated frac services agreement including certain component stimulation product and service costs have also declined in the nine months ended September 30, 2019. For the remainder of the year, we anticipate that these costs will continue a declining trend. Costs incurred for most oilfield products and services associated with operating our properties remained relatively stable during the nine months ended September 30, 2019 and are anticipated to remain as such for the remainder of 2019 with moderate declines in certain costs consistent with recent industry experience.

Sequential Quarterly Analysis

The following summarizes our key operating and financial highlights for the three months ended September 30, 2019, with comparison to the three months ended June 30, 2019. The year-over-year highlights for the quarter and nine-month periods are addressed in further detail under Financial Condition and Results of Operations that follow.

•

Daily production increased four percent to 29,003 barrels of oil equivalent per day, or BOEPD, from 27,845 BOEPD due primarily to the number of wells turned to sales during the third quarter of 2019, which included 20 gross (18.3 net) wells compared to eight gross (7.3 net) wells turned to sales in the second quarter of 2019. Of the wells turned to sales in the third quarter of 2019, ten gross (9.0 net) wells were turned to sales in late August and September of 2019. Total production increased five percent to 2,668 thousand barrels of oil equivalent, or MBOE, from 2,534 MBOE.

•

Product revenues declined approximately four percent to $118.4 million from $122.8 million due primarily to nine percent lower crude oil prices partially offset by six percent higher crude oil volume. NGL revenues were one percent higher due to seven percent higher volume substantially offset by five percent lower prices. Natural gas revenues declined 20 percent due to a three percent decrease in volume and an 18 percent decrease in prices.

•

Production and lifting costs (consisting of Lease operating expenses, or LOE, and Gathering, processing and transportation expenses, or GPT) increased on an absolute and per unit basis to $18.5 million and $6.92 per BOE from $16.8 million and $6.62 per BOE due primarily to higher utility charges, chemical costs and increased rates for crude oil gathering services, resulting from a contractual price increase, as well as the effects of higher production volume partially offset by lower repairs and maintenance.


•	Production and ad valorem taxes decreased on an absolute and per unit basis to $7.4 million and $2.77 per BOE from $7.6 million and $2.99 per BOE, respectively, due to lower overall product pricing and the effect of higher estimated valuations for ad valorem tax assessments that were recorded in the second quarter of 2019.


•	General and administrative, or G&A, expenses increased on an absolute and per unit basis to $6.9 million and $2.57 per BOE from $6.2 million and $2.46 per BOE, respectively, due primarily to higher overall compensation charges as well as higher consulting costs.


•	Depreciation, depletion and amortization, or DD&A, increased on an absolute basis to $46.5 million from $44.3 million due primarily to higher volume. DD&A decreased marginally on a per unit basis to $17.43 per BOE from $17.48 per BOE.


•	Operating income decreased to $40.0 million from $47.9 million due to the combined impact of the matters noted in the bullets above.

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



	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,
	2019			2019			2018			2019			2018
Total production (MBOE)	2,668			2,534			2,108			7,425			5,581
Average daily production (BOEPD)	29,003			27,845			22,912			27,196			20,444
Crude oil production (MBbl)	1,937			1,821			1,633			5,409			4,259
Crude oil production as a percent of total	73		%	72		%	77		%	73		%	76		%
Product revenues	$	118,379		$	122,823		$	126,803		$	345,839		$	314,958
Crude oil revenues	$	110,618		$	114,031		$	117,059		$	319,461		$	290,033
Crude oil revenues as a percent of total	93		%	93		%	92		%	92		%	92		%
Realized prices:
Crude oil ($ per Bbl)	$	57.12		$	62.63		$	71.67		$	59.06		$	68.10
NGLs ($ per Bbl)	$	8.54		$	9.01		$	22.41		$	11.25		$	20.64
Natural gas ($ per Mcf)	$	2.22		$	2.72		$	3.02		$	2.56		$	2.80
Aggregate ($ per BOE)	$	44.37		$	48.47		$	60.16		$	46.58		$	56.43
Prices adjusted for derivatives:
Crude oil ($ per Bbl)	$	56.90		$	58.07		$	62.36		$	58.26		$	59.84
Aggregate ($ per BOE)	$	44.21		$	45.20		$	52.94		$	46.00		$	50.13
Production and lifting costs:
Lease operating ($ per BOE)	$	4.45		$	4.09		$	4.70		$	4.48		$	4.64
Gathering, processing and transportation ($ per BOE)	$	2.47		$	2.53		$	2.34		$	2.28		$	2.30
Production and ad valorem taxes ($ per BOE)	$	2.77		$	2.99		$	3.39		$	2.78		$	3.05
General and administrative ($ per BOE) ¹	$	2.58		$	2.46		$	2.92		$	2.72		$	3.22
Depreciation, depletion and amortization ($ per BOE)	$	17.43		$	17.48		$	16.61		$	17.47		$	15.83
Capital expenditure program costs ²	$	99,068		$	90,872		$	104,589		$	291,228		$	313,852
Cash provided by operating activities ³	$	89,851		$	85,103		$	72,487		$	244,213		$	192,905
Cash paid for capital expenditures ⁴	$	115,792		$	89,455		$	121,909		$	291,733		$	323,259
Cash and cash equivalents at end of period	$	11,387		$	12,796		$	8,011		$	11,387		$	8,011
Debt outstanding at end of period, net	$	562,445		$	531,476		$	472,344		$	562,445		$	472,344
Credit available under credit facility at end of period	$	129,200		$	159,600		$	57,100		$	129,200		$	57,100
Net development wells drilled and completed	18.3			7.3			9.7			33.4			36.6

^{__________________________________________________________________________________}

Includes combined amounts of $0.39, $0.43 and $0.51 per BOE for the three months ended September 30, 2019, June 30, 2019 and September 30, 2018, respectively, and $0.53 and $0.76 for the nine months ended September 30, 2019 and 2018, 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.


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

Includes net cash received (paid) for derivative settlements of $(0.4) million, $(8.3) million and $(15.2) million for the three months ended September 30, 2019, June 30, 2019 and September 30, 2018, respectively, and $(4.3) million and $(35.2) million for the nine months ended September 30, 2019 and 2018, respectively. Reflects changes in operating assets and liabilities of $10.9 million, $8.4 million and $(6.1) million for the three months ended September 30, 2019, June 30, 2019 and September 30, 2018, respectively, and $12.9 million and $(2.1) million for the nine months ended September 30, 2019 and 2018, respectively.


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

Key Developments

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

Production and Development Plans

Total production for the third quarter of 2019 was 2,668 BOE, or 29,003 barrels of oil equivalent per day, or BOEPD, with approximately 73 percent, or 1,937 MBOE, of production from crude oil, 15 percent from NGLs and 12 percent from natural gas.

We drilled and turned 20 gross (18.3 net) wells to sales during the third quarter of 2019. Subsequent to September 30, 2019, we drilled and turned an additional three gross (2.6 net) wells to sales. As of November 1, 2019, we were drilling four gross (3.4 net) wells with two operated drilling rigs, two gross (1.9 net) wells were completing and two gross (1.7 net) wells were waiting on completion.

As of November 1, 2019, we had approximately 100,200 gross (87,300 net) acres in the Eagle Ford, net of expirations. Approximately 91 percent of our acreage is held by production and substantially all is operated by us.

Commodity Hedging Program

We have hedged a portion of our estimated future crude oil production from October 2019 through the end of 2020 with a mix of West Texas Intermediate, or WTI-, Light Louisiana Sweet, or LLS- and Magellan East Houston, or MEH- indexed swaps. In September 2019, we entered into contracts to hedge 4,000 barrels per day for the fourth quarter of 2019 at a WTI swap price of $56.48 per barrel and 2,000 barrels per day for the first quarter of 2020 at a WTI swap price of $56.05 per barrel. In November 2019, we entered into contracts to hedge an additional 4,000 barrels per day for the first quarter of 2020 at a WTI swap price of $56.40 per barrel and approximately 1,600 barrels per day for the full year 2020 at a WTI swap price of $53.88 per barrel. We are currently unhedged with respect to NGL and natural gas production. The following table summarizes our hedge positions, including the additional hedges mentioned above, for the periods presented:



	WTI Volumes	WTI Average Swap Price		LLS Volumes	LLS Average Swap Price		MEH Volumes		MEH Average Swap Price
	(Barrels per day)	($ per barrel)		(Barrels per day)	($ per barrel)		(Barrels per day)		($ per barrel)
Q4 2019	11,400	$	55.97	5,000	$	59.17	$	1,000	$	64.00
2020	10,100	$	54.97	—	—		2,000		$	61.03

Executive Transition

On November 4, 2019, the Company announced that Russell T. Kelley, Jr. had been appointed as the Company’s Senior Vice President, Chief Financial Officer and Treasurer, or SVP and CFO, effective November 13, 2019. Prior to the effective date of his appointment, Steven A. Hartman will continue to serve as SVP and CFO in accordance with a separation and transition agreement with the Company. We have incurred incremental G&A costs, certain of which will be recognized in the fourth quarter of 2019, in connection with Mr. Kelley’s appointment and Mr. Hartman’s separation.

Financial Condition

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the credit agreement, or the Credit Facility. The Credit Facility provides us with up to $1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is $500.0 million. As of November 1, 2019, we had $117.2 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. 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 production through the end of 2020. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

Capital Resources

Under our capital program for 2019, we anticipate capital expenditures, excluding acquisitions, to total between $350 million and $360 million for 2019 with over 95 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our 2019 capital spending primarily with cash from operating activities and, if necessary, borrowings under the Credit Facility. Based upon current price and production expectations for 2019, we believe that our cash from operating activities and borrowings under our Credit Facility will be sufficient to fund our operations through year-end 2019; however, future cash flows are subject to a number of variables and significant additional capital expenditures may be required to more fully develop our properties. For a detailed analysis of our historical capital expenditures, see the “Cash Flows” discussion that follows.

Cash on Hand and Cash From Operating Activities. As of November 1, 2019, we had approximately $3 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 three and nine months ended September 30, 2019, we borrowed $30.4 million and $49.4 million, respectively, net of repayments, 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
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended September 30, 2019	$	357,429	$	370,400	4.25	%
Nine months ended September 30, 2019	$	339,013	$	370,400	5.06	%

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.

Cash Flows

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



	Nine Months Ended
	September 30,			September 30,
	2019			2018
Cash flows from operating activities
Operating cash flows, net of working capital changes	$	275,328		$	244,591
Crude oil derivative settlements paid, net	(4,330		)	(35,191		)
Interest payments, net of amounts capitalized	(24,721		)	(15,174		)
Acquisition, divestiture and strategic transaction costs paid	(1,985		)	(557		)
Reorganization-related administration fees and costs paid	(79		)	(514		)
Consulting costs paid to former Executive Chairman	—			(250		)
Net cash provided by operating activities	244,213			192,905
Cash flows from investing activities
Acquisitions, net	(5,956		)	(85,387		)
Capital expenditures	(291,733		)	(323,259		)
Proceeds from sales of assets, net	215			7,989
Net cash used in investing activities	(297,474		)	(400,657		)
Cash flows from financing activities
Proceeds from credit facility borrowings, net of repayments	49,400			205,500
Debt issuance costs paid	(2,616		)	(754		)
Net cash provided by financing activities	46,784			204,746
Net decrease in cash and cash equivalents	$	(6,477	)	$	(3,006	)

Cash Flows from Operating Activities. The increase of $51.3 million in net cash provided by operating activities for the nine months ended September 30, 2019 compared to the corresponding period in 2018 was primarily attributable to: (i) approximately 33 percent higher production volume in the 2019 period despite approximately 17 percent lower overall product pricing, (ii) substantially lower net payments of derivative settlements in the 2019 period, (iii) two months of incremental net operating cash inflows from the acquisition of oil and gas assets from Hunt Oil Company, or the Hunt Acquisition, which was completed on March 1, 2018, (iv) lower payments in the 2019 period for reorganization-related administration costs and (v) the absence in the 2019 period of consulting costs paid to our former Executive Chairman that were paid in 2018 period. These items were partially offset by higher interest payments due to greater outstanding borrowings in the 2019 period and higher costs paid for acquisition, divestiture and strategic transaction costs in the 2019 period, including costs associated with the terminated merger transaction with Denbury.

Cash Flows from Investing Activities. In the 2019 period, we paid approximately $6 million for the acquisition of working interests in certain properties for which we are the operator from our joint working interest partners. In the 2018 period, we paid a total of $86.5 million in connection with the Hunt Acquisition and received a total of $1.1 million in connection with the final settlement of a 2017 acquisition transaction. As illustrated in the tables below, our cash payments for capital expenditures were lower during the 2019 period as compared to the 2018 period, due primarily to the employment of two drilling rigs through most of 2019 compared to three drilling rigs utilized during most of the comparable period in 2018. In addition, we received $0.2 million in proceeds from the sale of scrap tubular and well materials in the 2019 period while we received proceeds of $8.0 million in the 2018 period attributable to the sales of: (i) all of our Mid-Continent properties, (ii) undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana, (iii) certain undeveloped deep leasehold rights in Oklahoma, (iv) certain pipeline assets in our former Marcellus Shale operating region and (iv) scrap tubular and well materials.

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



	Nine Months Ended
	September 30,		September 30,
	2019		2018
Drilling and completion	$	282,421	$	302,888
Lease acquisitions and other land-related costs	2,352		4,239
Pipeline, gathering facilities and other equipment, net	6,137		6,502
Geological and geophysical (seismic) costs	318		223
	$	291,228	$	313,852

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:



	Nine Months Ended
	September 30,			September 30,
	2019			2018
Total capital expenditures program costs (from above)	$	291,228		$	313,852
Increase in accrued capitalized costs	(2,672		)	(1,833		)
Less:
Transfers from tubular inventory and well materials	(7,068		)	(4,905		)
Sales and use tax refunds received and applied to property accounts	(2,855		)	(643		)
Other, net	(78		)	—
Add:
Tubular inventory and well materials purchased in advance of drilling	6,767			7,245
Capitalized internal labor	3,177			2,432
Capitalized interest	3,234			7,111
Total cash paid for capital expenditures	$	291,733		$	323,259

Cash Flows from Financing Activities. The 2019 period includes borrowings of $62.4 million and repayments of $13.0 million under the Credit Facility which were used to fund a portion of our capital program as well as the aforementioned acquisition of working interests. The 2018 period includes borrowings of $205.5 million under the Credit Facility, a substantial portion of which was used to fund the Hunt Acquisition. We also paid $2.6 million and $0.8 million of debt issue costs in the 2019 and 2018 periods, respectively, in connection with amendments to the Credit Facility.

Capitalization

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



	September 30,			December 31,
	2019			2018
Credit facility	$	370,400		$	321,000
Second lien term loan, net	192,045			190,375
Total debt, net	562,445			511,375
Shareholders’ equity	516,658			447,355
	$	1,079,103		$	958,730
Debt as a % of total capitalization	52		%	53		%

Credit Facility. The Credit Facility provides for a $1.0 billion revolving commitment and $500 million borrowing base and a $25 million sublimit for the issuance of letters of credit. Our fall borrowing base re-determination is currently in process. The availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and October of each year. Additionally, the Credit Facility lenders may, at their discretion, 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 September 30, 2019 and December 31, 2018, respectively.

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 the extended maturity date of May 2024 or have repaid our Second Lien Facility in full, the maturity date of the Credit Facility will mean June 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 0.50% to 1.50% (2.00% to 3.00% prior to May 2019), determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate, or LIBOR, plus an applicable margin ranging from 1.50% to 2.50% (3.00% to 4.00% prior to May 2019), determined based on the average availability 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 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 September 30, 2019, the actual weighted-average interest

rate on the outstanding borrowings under the Credit Facility was 4.07%. Unused commitment fees are charged at a rate of 0.375% to 0.50% depending upon utilization.

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 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 September 30, 2019, the actual interest rate on the Second Lien Facility was 9.05%. 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): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums 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: during years one and two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.

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 4.00 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, and transactions with affiliates and other customary covenants.

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 September 30, 2019, 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. We have not yet pursued any technical amendment or other contractual alternative to address this matter. We are currently evaluating the potential impact of the eventual replacement of the LIBOR interest rate.

Results of Operations

As discussed in further detail in Notes 2 and 9 to the Condensed Consolidated Financial Statements, we have adopted Accounting Standards Codification Topic 842, Leases, or ASC Topic 842, effective January 1, 2019. We adopted ASC Topic 842 utilizing the optional transition approach. As a result of the adoption of ASC Topic 842, certain amounts included in LOE and G&A are not comparable between the 2019 and 2018 periods; however, we do not believe that such differences are material.

Production

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



	Total Production				Average Daily Production
	Three Months Ended		2019 vs. 2018		Three Months Ended		2019 vs. 2018
	September 30,	September 30,	Favorable		September 30,	September 30,	Favorable
	2019	2018	(Unfavorable)		2019	2018	(Unfavorable)
Crude oil (MBbl and BOPD)	1,937	1,633	304		21,050	17,753	3,297
NGLs (MBbl and BOPD)	415	267	148		4,513	2,899	1,614
Natural gas (MMcf and MMcfpd)	1,899	1,248	651		21	14	7
Total (MBOE and BOEPD)	2,668	2,108	560		29,003	22,912	6,091

	Three Months Ended		2019 vs. 2018		Three Months Ended		2019 vs. 2018
	September 30,	September 30,	Favorable		September 30,	September 30,	Favorable
	2019	2018	(Unfavorable)		2019	2018	(Unfavorable)
	(MBOE)				(BOEPD)
South Texas	2,668	2,081	587		29,003	22,622	6,381
Mid-Continent ¹	—	27	(27	)	—	290	(290	)
	2,668	2,108	560		29,003	22,912	6,091

	Nine Months Ended		2019 vs. 2018		Nine Months Ended		2019 vs. 2018
	September 30,	September 30,	Favorable		September 30,	September 30,	Favorable
	2019	2018	(Unfavorable)		2019	2018	(Unfavorable)
Crude oil (MBbl and BOPD)	5,409	4,259	1,150		19,814	15,599	4,215
NGLs (MBbl and BOPD)	1,119	700	419		4,100	2,565	1,535
Natural gas (MMcf and MMcfpd)	5,377	3,734	1,643		20	14	6
Total (MBOE and BOEPD)	7,425	5,581	1,843		27,196	20,444	6,752

	Nine Months Ended		2019 vs. 2018		Nine Months Ended		2019 vs. 2018
	September 30,	September 30,	Favorable		September 30,	September 30,	Favorable
	2019	2018	(Unfavorable)		2019	2018	(Unfavorable)
	(MBOE)				(BOE per day)
South Texas	7,425	5,417	2,008		27,196	19,841	7,355
Mid-Continent ¹	—	165	(165	)	—	603	(603	)
	7,425	5,581	1,843		27,196	20,444	6,752

_______________________

¹ Mid-Continent operations were sold on July 31, 2018.

Total production increased 27 percent and 33 percent during the three and nine month periods in 2019, respectively, due primarily to more productive and higher working interest wells turned to sales in the second half of 2018 through the third quarter of 2019 when compared to the corresponding periods in the second half of 2017 through the third quarter of 2018 as well as incremental production from the Hunt Acquisition. Crude oil production increased 19 percent and 27 percent during the three and nine month periods in 2019, respectively. These increases were partially offset by the effect of the divestiture in July 2018 of our former Mid-Continent operations, as well as natural production declines from our more mature Eagle Ford wells.

Approximately 73 percent of total production during each of the three and nine month periods in 2019 was attributable to crude oil when compared to approximately 77 percent and 76 percent during the corresponding periods in 2018. The decline in the crude oil composition of total production was due primarily to a consistently higher gas to oil ratio experienced with our recently drilled wells, primarily in the southeastern portion of our acreage holdings. During the three and nine month periods in 2019, we turned 20 gross (18.3 net) wells and 37 gross (33.4 net) wells to sales, respectively, compared to 10 gross (9.7 net) wells and 43 gross (36.6 net) wells during the corresponding periods in 2018.

Product Revenues and Prices

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



	Total Product Revenues							Product Revenues per Unit of Volume
	Three Months Ended				2019 vs. 2018			Three Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
								($ per unit of volume)
Crude oil	$	110,618	$	117,059	$	(6,441	)	$	57.12	$	71.67	$	(14.55	)
NGLs	3,546		5,976		(2,430		)	$	8.54	$	22.41	$	(13.87	)
Natural gas	4,215		3,768		447			$	2.22	$	3.02	$	(0.80	)
Total	$	118,379	$	126,803	$	(8,424	)	$	44.37	$	60.16	$	(15.79	)

	Three Months Ended				2019 vs. 2018			Three Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
								($ per BOE)
South Texas	$	118,379	$	126,168	$	(7,789	)	$	44.37	$	60.62	$	(16.25	)
Mid-Continent ¹	—		635		(635		)	$	—	$	23.76	$	(23.76	)
	$	118,379	$	126,803	$	(8,424	)	$	44.37	$	60.16	$	(15.79	)

	Nine Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
								($ per unit of volume)
Crude oil	$	319,461	$	290,033	$	29,428		$	59.06	$	68.10	$	(9.04	)
NGLs	12,596		14,455		(1,859		)	$	11.25	$	20.64	$	(9.39	)
Natural gas	13,782		10,470		3,312			$	2.56	$	2.80	$	(0.24	)
Total	$	345,839	$	314,958	$	30,881		$	46.58	$	56.43	$	(9.85	)

	Nine Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
								($ per BOE)
South Texas	$	345,839	$	311,028	$	34,811		$	46.58	$	57.42	$	(10.84	)
Mid-Continent ¹	—		3,930		(3,930		)	$	—	$	23.87	$	(23.87	)
	$	345,839	$	314,958	$	30,881		$	46.58	$	56.43	$	(9.85	)

_______________________

¹ Mid-Continent operations were sold on July 31, 2018.

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



	Three Months Ended September 30, 2019 vs. 2018								Nine Months Ended September 30, 2019 vs. 2018
	Revenue Variance Due to								Revenue Variance Due to
	Volume		Price			Total			Volume		Price			Total
Crude oil	$	21,741	$	(28,182	)	$	(6,441	)	$	78,358	$	(48,930	)	29,428
NGLs	3,328		(5,758		)	(2,430		)	8,650		(10,509		)	(1,859		)
Natural gas	1,966		(1,519		)	447			4,607		(1,295		)	3,312
	$	27,035	$	(35,459	)	$	(8,424	)	$	91,615	$	(60,734	)	$	30,881

Our product revenues during the three month period in 2019 decreased compared to the corresponding period in 2018 due primarily to approximately 20 percent lower crude oil prices partially offset by 19 percent higher volume. Approximately 27 percent higher crude oil volume partially offset by 13 percent lower pricing resulted in higher overall product revenues in the nine month period in 2019 compared to the corresponding period in 2018. NGL revenues declined in both the three and nine month period in 2019 due to substantially lower pricing (62 percent and 45 percent in the three- and nine-month periods) partially offset by 55 percent and 60 percent higher volumes, respectively. Higher natural gas revenues were primarily attributable to 52 percent and 44 percent higher volumes partially offset by 26 percent and nine percent lower pricing during the three and nine month periods in 2019, respectively. Total crude oil revenues were approximately 93 percent and 92 percent of our total revenues during the three and nine month periods in 2019 as compared to 92 percent during each of the three and nine month periods in 2018.

Realized Differentials

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



	Three Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
Realized crude oil prices per barrel	$	57.12	$	71.67	$	(14.55	)	$	59.06	$	68.10	$	(9.04	)
Weighted-average WTI prices	56.44		69.63		(13.19		)	57.10		66.90		(9.80		)
Realized differential to WTI	$	0.68	$	2.04	$	(1.36	)	$	1.96	$	1.20	$	0.76

While the overall magnitude of the margin has declined into the third quarter of 2019, we continue to realize premiums to the WTI index price for crude oil as the majority of our production is sold based on LLS or MEH pricing.

Effects of Derivatives

The following table reconciles crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Three Months Ended						2019 vs. 2018			Nine Months Ended						2019 vs. 2018
	September 30,			September 30,			Favorable			September 30,			September 30,			Favorable
	2019			2018			(Unfavorable)			2019			2018			(Unfavorable)
Crude oil revenues, as reported	$	110,618		$	117,059		$	(6,441	)	$	319,461		$	290,033		$	29,428
Derivative settlements, net	(423		)	(15,214		)	14,791			(4,330		)	(35,191		)	30,861
	$	110,195		$	101,845		$	8,350		$	315,131		$	254,842		$	60,289

Crude oil prices per Bbl	$	57.12		$	71.67		$	(14.55	)	$	59.06		$	68.10		$	(9.04	)
Derivative settlements per Bbl	(0.22		)	(9.32		)	9.10			(0.80		)	(8.26		)	7.46
	$	56.90		$	62.36		$	(5.45	)	$	58.26		$	59.84		$	(1.58	)

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 gains recognized for the periods presented:



	Three Months Ended				2019 vs. 2018		Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable		September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)		2019		2018		(Unfavorable)
Gain on sales of assets, net	$	77	$	2	$	75	$	118	$	81	$	37

There were insignificant net gains recognized during the three and nine month periods in 2019 and 2018 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 that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our current operations.

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



	Three Months Ended				2019 vs. 2018		Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable		September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)		2019		2018		(Unfavorable)
Other revenues, net	$	848	$	380	$	468	$	1,342	$	937	$	405

Other revenues, net increased during each of the three and nine month periods in 2019 from the corresponding periods in 2018 due primarily to higher marketing and water disposal revenues attributable to higher production in each of the periods in 2019 compared to the corresponding periods in 2018 partially offset by certain unscheduled repairs and maintenance costs incurred during the second quarter of 2019 at our water disposal facilities.

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:



	Three Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
Lease operating	$	11,868	$	9,898	$	(1,970	)	$	33,234	$	25,924	$	(7,310	)
Per unit of production ($ per BOE)	$	4.45	$	4.70	$	0.25		$	4.48	$	4.64	$	0.16
% change per unit of production					5.3		%					3.4		%

LOE increased on an absolute basis, but declined on a per unit basis during both the three and nine month periods in 2019 when compared to the corresponding periods in 2018. The absolute increases were due primarily to higher production volume as discussed above and higher utility costs, as well as the effects of two additional months of production in the 2019 nine-month period attributable to the Hunt Acquisition. The higher production volume also had the effect of decreasing the overall per unit cost, particularly those costs that have a higher fixed cost component.

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.

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



	Three Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
Gathering, processing and transportation	$	6,600	$	4,928	$	(1,672	)	$	16,937	$	12,861	$	(4,076	)
Per unit of production ($ per BOE)	$	2.47	$	2.34	$	(0.13	)	$	2.28	$	2.30	$	0.02
% change per unit of production					(5.6		)%					0.9		%

GPT expense increased on an absolute basis during the three and nine month periods in 2019 when compared to the corresponding periods in 2018 due primarily to substantially higher production volumes as discussed above. Per unit costs increased in the three month period in 2019 and declined marginally in the nine month period in 2019 compared to the corresponding periods in 2018 due primarily to a scheduled rate increase effective August 1, 2019, for crude oil gathering services provided by Nuevo Dos Gathering & Transportation, LLC, or Nuevo G&T, successor to Republic Midstream, LLC, 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.

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 contemporary commodity prices.

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



	Three Months Ended						2019 vs. 2018			Nine Months Ended						2019 vs. 2018
	September 30,			September 30,			Favorable			September 30,			September 30,			Favorable
	2019			2018			(Unfavorable)			2019			2018			(Unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	5,511		$	6,121		$	610		$	16,067		$	15,021		$	(1,046	)
Ad valorem taxes	1,890			1,031			(859		)	4,605			2,018			(2,587		)
	$	7,401		$	7,152		$	(249	)	$	20,672		$	17,039		$	(3,633	)
Per unit production ($ per BOE)	$	2.77		$	3.39		$	0.62		$	2.78		$	3.05		$	0.27
Production/severance tax rate as a percent of product revenue	4.7		%	4.8		%				4.6		%	4.8		%

Production taxes increased on an absolute basis, but declined on a per unit basis during the three and nine month periods in 2019 when compared to the corresponding periods in 2018 due primarily to increased production volume despite lower overall commodity sales prices. Accruals for ad valorem taxes also increased substantially for the 2019 periods due to a higher commodity-price based valuation assessment assumption 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:



	Three Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
Primary G&A	$	5,830	$	5,090	$	(740	)	$	16,272	$	13,695	$	(2,577	)
Share-based compensation (equity-classified)	1,046		1,021		(25		)	3,101		3,472		371
Significant special charges:
Acquisition, divestiture and strategic transaction costs	—		44		44			800		531		(269		)
Executive retirement costs	—		—		—			—		250		250
Total G&A	$	6,876	$	6,155	$	(721	)	$	20,173	$	17,948	$	(2,225	)
Per unit of production ($ per BOE)	$	2.58	$	2.92	$	0.34		$	2.72	$	3.22	$	0.50
Per unit of production excluding share-based compensation and other significant special charges identified above ($ per BOE)	$	2.18	$	2.41	$	0.23		$	2.19	$	2.45	$	0.26

Our primary G&A expenses increased on an absolute and decreased on a per unit basis during both the three and nine month periods in 2019 compared to the corresponding periods in 2018. The absolute increases are due primarily to the effects of higher payroll, benefits and support costs attributable to a higher overall employee headcount. In addition, we incurred higher occupancy costs and higher consulting and related costs including those associated with the SVP/CFO transition in the 2019 periods. Higher production volume had the effect of reducing G&A per unit of production during each of the 2019 three and nine month periods.

Equity-classified 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 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. A substantial portion of the share-based compensation expense is attributable to the RSU and PRSU grants made in the normal course in January 2017 and RSU grants in September 2016 in connection with our reorganization. The remainder is attributable to grants of RSUs and PRSUs to certain employees upon their hiring or as a result of promotion subsequent to the first quarter of 2017. The nine month period in 2018 includes a charge of $0.6 million attributable to the accelerated vesting of certain RSUs and PRSUs in connection with the retirement of our former Executive Chairman in February 2018.

During the first half of 2019, we incurred consulting and other costs, including legal and other professional fees primarily associated with the previously announced merger transaction with Denbury which was mutually terminated in March 2019. The 2018 period includes similar transaction costs associated with the Hunt Acquisition as well as certain costs attributable to the aforementioned retirement of our former Executive Chairman.

Depreciation, Depletion and Amortization

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



	Three Months Ended				2019 vs. 2018			Nine Months Ended				2019 vs. 2018
	September 30,		September 30,		Favorable			September 30,		September 30,		Favorable
	2019		2018		(Unfavorable)			2019		2018		(Unfavorable)
DD&A expense	$	46,519	$	35,016	$	(11,503	)	$	129,687	$	88,370	$	(41,317	)
DD&A Rate ($ per BOE)	$	17.43	$	16.61	$	(0.82	)	$	17.47	$	15.83	$	(1.64	)

DD&A increased on an absolute and per unit basis during both the three and nine month periods ended in 2019 when compared to the corresponding periods in 2018. Higher production volume provided for an increase of approximately $9.3 million and $29.2 million while $2.2 million and $12.2 million was attributable to the higher DD&A rates in the 2019 periods. The higher DD&A rates in the 2019 periods are attributable to higher costs added to the full cost pool in the 2019 period.

Interest Expense

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



	Three Months Ended						2019 vs. 2018			Nine Months Ended						2019 vs. 2018
	September 30,			September 30,			Favorable			September 30,			September 30,			Favorable
	2019			2018			(Unfavorable)			2019			2018			(Unfavorable)
Interest on borrowings and related fees	$	8,945		$	8,897		$	(48	)	$	27,960		$	22,675		$	(5,285	)
Accretion of original issue discount	188			172			(16		)	551			505			(46		)
Amortization of debt issuance costs	608			693			85			1,993			2,004			11
Capitalized interest	(1,005		)	(2,440		)	(1,435		)	(3,234		)	(7,111		)	(3,877		)
	$	8,736		$	7,322		$	(1,414	)	$	27,270		$	18,073		$	(9,197	)

Interest expense increased during the three and nine month periods in 2019 as compared to the corresponding periods in 2018 due primarily to higher outstanding balances under the Credit Facility partially offset by the effect of lower interest rates. Weighted-average balances under the Credit Facility were higher in the 2019 periods compared to the 2018 periods by approximately $89 million and $133 million while the weighted-average interest rates were lower during these same periods by 157 and 46 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 capitalized a larger portion of interest during the 2018 periods as we maintained a substantially larger 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.

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



	Three Months Ended					2019 vs. 2018		Nine Months Ended						2019 vs. 2018
	September 30,		September 30,			Favorable		September 30,			September 30,			Favorable
	2019		2018			(Unfavorable)		2019			2018			(Unfavorable)
Crude oil derivative gains (losses)	$	24,248	$	(40,689	)	$	64,937	$	(30,166	)	$	(111,725	)	$	81,559

In the three month period in 2019, the forward curve for commodity prices declined relative to our weighted-average hedged prices resulting in net gains for our derivative portfolio and lower net losses for the nine month period. In the 2018 periods, the forward curve moved in the opposite direction resulting in net losses. We paid net cash settlements of $0.4 million and $4.3 million in the three and nine month periods in 2019, respectively, and paid net cash settlements of $15.2 million and $35.2 million in the three and nine month periods in 2018, respectively.

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:



	Three Months Ended					2019 vs. 2018			Nine Months Ended					2019 vs. 2018
	September 30,			September 30,		Favorable			September 30,			September 30,		Favorable
	2019			2018		(Unfavorable)			2019			2018		(Unfavorable)
Other, net	$	(248	)	$	241	$	(489	)	$	(134	)	$	167	$	(301	)

Other, net income (expense) decreased during both the three and nine month periods in 2019 as compared to the corresponding periods in 2018 due primarily to the write-off in the 2019 three month period of $0.2 million attributable to acquisition transactions in prior years that were no longer deemed recoverable. This charge was partially offset in the nine month period in 2019 by recoveries of sales and use taxes attributable to previously divested properties. Each of the periods in 2018 reflect the recoveries of joint interest receivable balances previously written-off in connection with the bankruptcy of a former partner and the reversal of a litigation reserve, partially offset by interest charges applicable to a settlement with a royalty owner. Each of the three and nine month periods includes comparable charges of less than $0.1 million associated with our retiree benefit plans.

Income Taxes

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



	Three Months Ended						2019 vs. 2018			Nine Months Ended						2019 vs. 2018
	September 30,			September 30,			Favorable			September 30,			September 30,			Favorable
	2019			2018			(Unfavorable)			2019			2018			(Unfavorable)
Income tax (expense) benefit	$	(942	)	$	10		$	(952	)	$	(1,736	)	$	(153	)	$	(1,583	)
Effective tax rate	1.7		%	0.1		%				2.5		%	0.6		%

We recognized a federal and state income tax expense for the nine months ended September 30, 2019 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 2.5%, which related to Texas deferred tax expense. The effect of the valuation allowance, as well as a reclassification of $1.2 million from deferred tax assets to the current income tax receivable for refundable alternative minimum tax, or AMT, credit carryforwards, was to adjust our deferred tax asset to a deferred tax liability position of $1.0 million as of September 30, 2019. We recognized a federal income tax expense for the nine months ended September 30, 2018 at the blended rate of 21.6% which was similarly offset by a valuation allowance against our net deferred tax assets. We recorded an adjustment of $0.2 million to the deferred tax asset related to sequestration of a portion of the aforementioned AMT credit carryforward resulting in an effective tax rate of 0.6%. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, due primarily to cumulative losses.

Off Balance Sheet Arrangements

As of September 30, 2019, 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, 2018.

Disclosure of the Impact of Recently Issued Accounting Pronouncements Pending Adoption

In June 2016, the Financial Accounting Standards Board, or FASB, issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments, or ASU 2016–13, which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners which have a higher credit risk than those associated with our traditional customer receivables. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are continuing to evaluate the requirements as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. We plan to adopt ASU 2016–13 effective January 1, 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 September 30, 2019, we had borrowings of $370.4 million under the Credit Facility and $200 million under the Second Lien Facility at interest rates of 4.07% and 9.05%, 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 $5.7 million on an annual basis.

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 September 30, 2019, our commodity derivative portfolio was in a net assets position. The contracts associated with this position are with eight 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 nine months ended September 30, 2019, we reported net commodity derivative loss of $30.2 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 September 30, 2019:



		Average	Weighted
		Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2019	Swaps-WTI	11,398	$	55.97	$	2,804	$	—
Fourth quarter 2019	Swaps-LLS	5,000	$	59.17	995		—
Fourth quarter 2019	Swaps-MEH	1,000	$	64.00	131		—
First quarter 2020	Swaps-WTI	9,000	$	55.19	2,942		—
First quarter 2020	Swaps-MEH	2,000	$	61.03	114		—
Second quarter 2020	Swaps-WTI	7,000	$	54.94	3,220		—
Second quarter 2020	Swaps-MEH	2,000	$	61.03	90		—
Third quarter 2020	Swaps-WTI	7,000	$	54.94	3,878		—
Third quarter 2020	Swaps-MEH	2,000	$	61.03	100		—
Fourth quarter 2020	Swaps-WTI	7,000	$	54.94	4,203		—
Fourth quarter 2020	Swaps-MEH	2,000	$	61.03	96		—
Settlements to be paid in subsequent period							368

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 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 $10.00 per Bbl of Crude Oil ($ in millions)
	Increase			Decrease
Effect on the fair value of crude oil derivatives ¹	$	(50.2	)	$	50.2
Effect of crude oil price changes for the remainder of 2019 on operating income, excluding derivatives ²	$	13.3		$	(13.3	)

_____________________________


¹	Based on derivatives outstanding as of September 30, 2019.


²	These 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 September 30, 2019. 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 September 30, 2019, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2019, 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, 2018.


Item 5.	Other Information.

None.


Item 6.	Exhibits.



(10.1)	Separation and Transition Agreement, entered into as of July 1, 2019, between Penn Virginia Corporation and Steven A. Hartman (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on July 8, 2019).

(10.2)	Form of Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 6, 2019).

(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 September 30, 2019, 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

November 8, 2019	By:	/s/ STEVEN A. HARTMAN
		Steven A. Hartman
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

November 8, 2019	By:	/s/ TAMMY L. HINKLE
		Tammy L. Hinkle
		Vice President and Controller
		(Principal Accounting Officer)