UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~September~~June 30, ~~2017~~2018



¨	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)

14701 ST. MARY’S LANE, SUITE 275

HOUSTON, TX 77079

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ý 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. ~~(Check One)~~



Large accelerated filer	o		Accelerated filer	oý
Non-accelerated filer	o	(Do not check if a smaller reporting company)	Smaller reporting company	ý o
			Emerging growth company	o

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 ý

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 ý No ¨

As of ~~November~~August 3, ~~2017, 15,004,270~~2018, 15,058,480 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended ~~September~~June 30, ~~2017~~2018

Table of Contents

					Part I - Financial Information
Item		Page		Page
1.	Financial Statements (unaudited).		Financial Statements.
	Condensed Consolidated Statements of Operations	3	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income	5	Condensed Consolidated Statements of Comprehensive Income	4
	Condensed Consolidated Balance Sheets	6	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	7	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements:		Notes to Condensed Consolidated Financial Statements:
	1. Nature of Operations	8	1. Nature of Operations	7
	2. Basis of Presentation	8	2. Basis of Presentation	7
	3. Acquisitions	10	3. Acquisitions and Divestitures	8
	4. Bankruptcy Proceedings and Emergence	11	4. Bankruptcy Proceedings and Emergence	11
	5. Accounts Receivable and Major Customers	11	5. Accounts Receivable and Revenues from Contracts with Customers	11
	6. Derivative Instruments	12	6. Derivative Instruments	13
	7. Property and Equipment	14	7. Property and Equipment	15
	8. Long-Term Debt	14	8. Long-Term Debt	15
	9. Income Taxes	16	9. Income Taxes	17
	10. Exit Activities	16	10. Executive Retirement	17
	11. Additional Balance Sheet Detail	17	11. Additional Balance Sheet Detail	18
	12. Fair Value Measurements	17	12. Fair Value Measurements	19
	13. Commitments and Contingencies	19	13. Commitments and Contingencies	20
	14. Shareholders’ Equity	19	14. Shareholders’ Equity	20
	15. Share-Based Compensation and Other Benefit Plans	19	15. Share-Based Compensation and Other Benefit Plans	21
	16. Interest Expense	21	16. Interest Expense	21
	17. Earnings (Loss) per Share	22	17. Earnings per Share	22
Forward-Looking Statements	Forward-Looking Statements	23	Forward-Looking Statements	23
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Overview and Executive Summary	24	Overview and Executive Summary	24
	Key Developments	26	Key Developments	26
	Financial Condition	28	Financial Condition	27
	Results of Operations	32	Results of Operations	31
	Critical Accounting Estimates	40	Off Balance Sheet Arrangements	37
			Critical Accounting Estimates	37
3.	Quantitative and Qualitative Disclosures About Market Risk.	41	Quantitative and Qualitative Disclosures About Market Risk.	38
4.	Controls and Procedures.	41	Controls and Procedures.	40
Part II - Other Information
1.	Legal Proceedings.	42	Legal Proceedings.	41
1A.	Risk Factors.	42	Risk Factors.	41
6.	Exhibits.	42	Exhibits.	41
Signatures	Signatures	43	Signatures	42

Part I. FINANCIAL INFORMATION


Item 1.	Financial Statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)

Successor Predecessor
Period From Period From
Three Months Ended September 13, 2016 Through July 1, 2016 Through
September 30, 2017 September 30, 2016 September 12, 2016
Revenues
Crude oil $ 29,963
$ 5,508
$ 23,392
Natural gas liquids 2,393
333
1,680
Natural gas 1,977
475
1,889
Gain on sales of assets, net 9
—
504
Other, net 117
33
(804 )
Total revenues 34,459
6,349
26,661
Operating expenses
Lease operating 5,254
756
4,209
Gathering, processing and transportation 2,399
576
4,767
Production and ad valorem taxes 1,668
375
574
General and administrative 6,952
1,476
6,895
Exploration —
—
4,641
Depreciation, depletion and amortization 10,659
2,029
8,024
Total operating expenses 26,932
5,212
29,110
Operating income (loss) 7,527
1,137
(2,449 )
Other income (expense)
Interest expense (1,202 ) (218 ) (1,363 )
Derivatives (12,275 ) (4,369 ) 8,934
Other, net 3
9
(2,154 )
Reorganization items, net —
—
1,152,373
Income (loss) before income taxes (5,947 ) (3,441 ) 1,155,341
Income tax benefit (expense) —
—
—
Net income (loss) (5,947 ) (3,441 ) 1,155,341
Preferred stock dividends —
—
—
Net income (loss) attributable to common shareholders $ (5,947 ) $ (3,441 ) $ 1,155,341
Net income (loss) per share:
Basic $ (0.40 ) $ (0.23 ) $ 12.94
Diluted $ (0.40 ) $ (0.23 ) $ 10.37

Weighted average shares outstanding – basic 14,994
14,992
89,292
Weighted average shares outstanding – diluted 14,994
14,992
111,458

~~See accompanying notes to condensed consolidated financial statements.~~

~~PENN VIRGINIA CORPORATION~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS~~ – ~~unaudited~~

~~(in thousands, except per share data)~~


	Successor						Predecessor
				Period From			Period From
	Nine Months Ended			September 13, 2016 Through			January 1, 2016 Through			Three Months Ended June 30,						Six Months Ended June 30,
	September 30, 2017			September 30, 2016			September 12, 2016			2018			2017			2018			2017
Revenues
Crude oil	$	92,387		$	5,508		$	81,377		$	101,716		$	32,351		$	172,974		$	62,424
Natural gas liquids	6,738			333			6,064			5,533			2,043			8,479			4,345
Natural gas	6,200			475			6,208			3,912			1,880			6,702			4,223
(Loss) gain on sales of assets, net	(60		)	—			1,261
Other, net	462			33			(600		)
Gain (loss) on sales of assets, net										4			(134		)	79			(69		)
Other revenues, net										415			142			557			345
Total revenues	105,727			6,349			94,310			111,580			36,282			188,791			71,268
Operating expenses
Lease operating	15,540			756			15,626			8,730			5,370			16,026			10,286
Gathering, processing and transportation	7,505			576			13,235			4,574			2,555			7,933			5,106
Production and ad valorem taxes	5,766			375			3,490			5,795			2,119			9,887			4,098
General and administrative	14,800			1,476			38,945			5,322			3,702			11,793			7,809
Exploration	—			—			10,288
Depreciation, depletion and amortization	31,545			2,029			33,582			31,273			11,076			53,354			20,886
Total operating expenses	75,156			5,212			115,166			55,694			24,822			98,993			48,185
Operating income (loss)	30,571			1,137			(20,856		)
Operating income										55,886			11,460			89,798			23,083
Other income (expense)
Interest expense	(3,014		)	(218		)	(58,018		)	(6,150		)	(1,274		)	(10,751		)	(1,812		)
Derivatives	15,802			(4,369		)	(8,333		)	(52,241		)	11,061			(71,036		)	28,077
Other, net	104			9			(3,184		)	(16		)	82			(74		)	62
Reorganization items, net	—			—			1,144,993
Income (loss) before income taxes	43,463			(3,441		)	1,054,602			(2,521		)	21,329			7,937			49,410
Income tax benefit (expense)	—			—			—
Income tax expense										—			—			(163		)	—
Net income (loss)	43,463			(3,441		)	1,054,602			$	(2,521	)	$	21,329		$	7,774		$	49,410
Preferred stock dividends	—			—			(5,972		)
Net income (loss) attributable to common shareholders	$	43,463		$	(3,441	)	$	1,048,630
Net income (loss) per share:
Basic	$	2.90		$	(0.23	)	$	11.91		$	(0.17	)	$	1.42		$	0.52		$	3.30
Diluted	$	2.89		$	(0.23	)	$	8.50		$	(0.17	)	$	1.42		$	0.51		$	3.27

Weighted average shares outstanding – basic	14,993			14,992			88,013			15,058			14,992			15,050			14,992
Weighted average shares outstanding – diluted	15,062			14,992			124,087			15,058			15,050			15,171			15,097

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)

Successor Predecessor
Period From Period From
Three Months Ended September 13, 2016 Through July 1, 2016 Through
September 30, 2017 September 30, 2016 September 12, 2016
Net income (loss) $ (5,947 ) $ (3,441 ) $ 1,155,341
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016 —
—
(383 )
—
—
(383 )
Comprehensive income (loss) $ (5,947 ) $ (3,441 ) $ 1,154,958


	Successor					Predecessor
			Period From			Period From
	Nine Months Ended		September 13, 2016 Through			January 1, 2016 Through			Three Months Ended June 30,					Six Months Ended June 30,
	September 30, 2017		September 30, 2016			September 12, 2016			2018			2017		2018		2017
Net income (loss)	$	43,463	$	(3,441	)	$	1,054,602		$	(2,521	)	$	21,329	$	7,774	$	49,410
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016	—		—			(421		)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2018 and 2017, respectively									—			—		—		—
	—		—			(421		)	—			—		—		—
Comprehensive income (loss)	$	43,463	$	(3,441	)	$	1,054,181		$	(2,521	)	$	21,329	$	7,774	$	49,410

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,			June 30,		December 31,
	2017		2016			2018		2017
Assets
Current assets
Cash and cash equivalents	$	7,487	$	6,761		$	11,521	$	11,017
Accounts receivable, net of allowance for doubtful accounts	48,096		29,095			71,572		69,821
Derivative assets	6,140		—			33		—
Other current assets	3,115		3,028			5,194		6,250
Total current assets	64,838		38,884			88,320		87,088
Property and equipment, net (full cost method)	486,060		247,473			791,624		529,059
Derivative assets	2,520		—			54		—
Deferred income taxes						4,780		4,943
Other assets	8,823		5,329			2,956		8,507
Total assets	$	562,241	$	291,686		$	887,734	$	629,597

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	62,236	$	49,697		$	127,982	$	96,181
Derivative liabilities	13,634		12,932			63,257		27,777
Total current liabilities	75,870		62,629			191,239		123,958
Other liabilities	4,631		4,072			5,493		4,833
Derivative liabilities	4,923		14,437			29,566		13,900
Long-term debt, net	245,055		25,000			432,824		265,267

Commitments and contingencies (Note 13)

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; 15,004,270 and 14,992,018 shares issued as of September 30, 2017 and December 31, 2016, respectively	150		150
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,058,480 and 15,018,870 shares issued as of June 30, 2018 and December 31, 2017, respectively						151		150
Paid-in capital	193,372		190,621			195,980		194,123
Retained earnings (accumulated deficit)	38,167		(5,296		)
Retained earnings						32,481		27,366
Accumulated other comprehensive income	73		73			—		—
Total shareholders’ equity	231,762		185,548			228,612		221,639
Total liabilities and shareholders’ equity	$	562,241	$	291,686		$	887,734	$	629,597

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Successor						Predecessor
				Period From			Period From
	Nine Months Ended			September 13, 2016 Through			January 1, 2016 Through			Six Months Ended June 30,
	September 30, 2017			September 30, 2016			September 12, 2016			2018			2017
Cash flows from operating activities
Net income (loss)	$	43,463		$	(3,441	)	$	1,054,602
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash reorganization items	—			—			(1,178,302		)
Net income										$	7,774		$	49,410
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	31,545			2,029			33,582			53,354			20,886
Accretion of firm transportation obligation	—			—			317
Derivative contracts:
Net (gains) losses	(15,802		)	4,369			8,333			71,036			(28,077		)
Cash settlements, net	(1,670		)	—			48,008			(19,977		)	(2,458		)
Loss (gain) on sales of assets, net	60			—			(1,261		)
Non-cash exploration expense	—			—			6,038
Deferred income tax expense										163			—
(Gain) loss on sales of assets, net										(79		)	69
Non-cash interest expense	1,362			38			22,188			1,644			988
Share-based compensation (equity-classified)	2,707			—			1,511			2,451			1,694
Other, net	59			—			(13		)	26			38
Changes in operating assets and liabilities, net	(11,430		)	585			35,244			4,026			(6,533		)
Net cash provided by operating activities	50,294			3,580			30,247			120,418			36,017

Cash flows from investing activities
Acquisition, net	(200,162		)	—			—
Acquisitions, net										(86,835		)	—
Capital expenditures	(67,844		)	—			(15,359		)	(201,350		)	(43,583		)
Proceeds from sales of assets, net	—			—			224			2,525			—
Other, net	—			—			1,186
Net cash used in investing activities	(268,006		)	—			(13,949		)	(285,660		)	(43,583		)

Cash flows from financing activities
Proceeds from credit facility borrowings	39,000			—			75,350			166,500			14,000
Repayment of credit facility borrowings	(7,000		)	(21,000		)	(119,121		)	—			(2,000		)
Proceeds from second lien facility, net	196,000			—			—
Debt issuance costs paid	(9,562		)	—			(3,011		)	(754		)	(1,090		)
Proceeds received from rights offering, net	55			—			49,943			—			55
Other, net	(55		)	—			—			—			(55		)
Net cash provided by (used in) financing activities	218,438			(21,000		)	3,161
Net increase (decrease) in cash and cash equivalents	726			(17,420		)	19,459
Net cash provided by financing activities										165,746			10,910
Net increase in cash and cash equivalents										504			3,344
Cash and cash equivalents – beginning of period	6,761			31,414			11,955			11,017			6,761
Cash and cash equivalents – end of period	$	7,487		$	13,994		$	31,414		$	11,521		$	10,105

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	1,596		$	—		$	4,331		$	8,953		$	795
Income taxes, net of (refunds)	$	—		$	—		$	(35	)
Reorganization items, net	$	1,098		$	—		$	30,990		$	442		$	901
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities	$	—		$	—		$	140,952
Changes in accounts receivable related to acquisitions										$	(26,631	)	$	—
Changes in other assets related to acquisitions										$	(2,469	)	$	—
Changes in accrued liabilities related to acquisitions										$	(15,099	)	$	—
Changes in accrued liabilities related to capital expenditures	$	8,140		$	—		$	(11,301	)	$	12,231		$	2,322
Derivatives settled to reduce outstanding debt	$	—		$	—		$	51,979
Changes in other liabilities for asset retirement obligations related to acquisitions										$	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~~June 30, ~~2017~~2018

(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 primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in Gonzales, Lavaca and DeWitt Counties in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash.


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, ~~2016~~2017. Operating results for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018, are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2017~~2018.

~~Comparability~~Reclassifications

We have reclassified certain amounts included within “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet as of ~~Financial Statements~~December 31, 2017, as disclosed in Note 11, in order to ~~Prior Periods~~conform to the current period presentation.

WeAdoption of Recently Issued Accounting Pronouncements

Effective January 1, 2018, we adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors.

Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends.

We have recasted amounts for equity-classified share-based compensation recognized as a component of “General and administrative” expenses from the amounts originally reported for the Predecessor period from July 1, 2016 through September 12, 2016 to correct for an immaterial error identified by management and disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016. Previously reported expense associated with this matter was decreased by $5.3 million for the period from July 1, 2016 through September 12, 2016. Our Predecessor net income for the period from July 1, 2016 through September 12, 2016 increased by an identical amount and our net income per basic and diluted share increased by $0.06 and $0.05. The Predecessor net income and earnings per share measures were unchanged for the period from January 1, 2016 through September 12, 2016.

~~Going Concern Presumption~~

Our unaudited Condensed Consolidated Financial Statements for the Successor periods 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, other than certain events described in Notes 3 and 6, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

~~Recently Issued Accounting Pronouncements~~

~~In March 2017, the Financial Accounting Standards Board (“FASB”) issued~~ Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) ~~which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance~~. ASU 2017–07 requires employers to disaggregate the service cost component from the other components of net periodic benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net periodic benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is ~~effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be~~ applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather there are interest and other costs associated with the legacy obligations. ~~Upon the adoption of~~As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, ~~will be presented~~which was less than $0.1 million, has been included as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of ~~Operations. These~~Operations for each of the three and six months ended June 30, 2017. Prior to 2018, all costs ~~are currently recognized as a component of “General and administrative” expenses. The total cost~~ associated with these plans ~~is generally less than $0.1 million on an annual basis~~were included in the “General and ~~is therefore not material.~~administrative” (“G&A”) expenses caption.

Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification (“ASC”) Topic 606, Revenues from Contracts with Customers (“ASC Topic 606”). We ~~will adopt ASU 2017–07 in January 2018.~~adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASC Topic 606.

Recently Issued Accounting Pronouncements Pending Adoption

In June 2016, the ~~FASB~~Financial Accounting Standards Board (“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 and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry.

In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842, Leases (“ASC Topic 842”) which supersedes all current GAAP with respect to leases. Consistent with current GAAP, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ~~ASU 2016–02~~ASC Topic 842 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ~~ASU 2016–02~~ASC Topic 842 is January 1, 2019, with early adoption permitted. ~~We believe that ASU 2016–02~~

ASC Topic 842 will ~~likely~~ be applicable to ~~our oil and natural gas gathering commitment arrangements as described in Note 13,~~ our existing leases for office facilities and certain office equipment, vehicles and certain field equipment, land easements and similar arrangements for rights-of-way, and potentially to certain drilling rig and completion contracts with terms in excess of ~~twelve~~12 months, to the extent we may have such contracts in the future. In addition, we believe that our crude oil and natural gas gathering commitment arrangements, as described in Note 13, include provisions that could be construed as leases. Our crude oil and natural gas gathering arrangements are fairly complex and ~~involve~~include, among other provisions, multiple elements and term lengths, certain volumetric-based minimums and varying degrees of optionality available to both us and the service providers. Furthermore, these arrangements have certain material payment terms that are variable in nature which, depending upon the outcome of our analysis and resulting conclusions, could ~~be construed~~have a significant impact on the amounts recognized as ~~leases.~~right of use assets and corresponding lease liabilities. We anticipate that the adoption of ASC Topic 842 may significantly increase our total assets and liabilities. Accordingly, we are continuing to evaluate the effect that ~~ASU 2016–02~~ASC Topic 842 will have on our Consolidated Financial Statements and related ~~disclosures as well as~~disclosures. We plan to adopt ASC Topic 842 on the ~~period for which we~~effective date in 2019 using the optional transition method and will ~~adopt~~recognize a cumulative-effect adjustment to the ~~standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019.~~opening balance of retained earnings. We are also continuing to monitor developments regarding ~~ASU 2016–02~~ASC Topic 842 that are unique to our industry.

~~In May 2014,~~Going Concern Presumption

Our unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the ~~FASB issued ASU 2014–09,~~ ~~Revenues from Contracts with Customers~~ ~~(“ASU 2014–09”), which requires an entity to recognize~~realization of assets and the ~~amount~~satisfaction of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyancesliabilities and ~~joint interest arrangements~~other commitments in the ~~oil and gas industry are not expected to be significantly impacted by ASU 2014–09, the terms~~normal course of the individual commodity purchase, joint operating agreements and other contracts underlying these types of transactions will determine the appropriate recognition, measurement and disclosure once ASU 2014–09business.

Subsequent Events

Management has been adopted. Also, to the extent applicable, we are considering our participation in certain of these transactions as either a principal or agent. In addition, the recognition, measurement and disclosure of producer imbalances and other non-product revenues, including our ancillary marketing,

~~gathering and transportation and water disposal revenues, while not significant, could be impacted to some degree. Our non-product revenues are projected to represent less than $1 million~~evaluated all of our ~~total revenues on an annualized basis; however, that level could rise in future periods based on~~activities through the ~~potential expansion and growth~~issuance date of our ~~operations. In summary,~~Condensed Consolidated Financial Statements and has concluded that, with the exception of ~~more expansive disclosures, we~~the divestiture of our Mid-Continent oil and gas properties as described in Note 3, no subsequent events have ~~not identified any potentially material impact attributable to ASU 2014–09. While we are continuing to evaluate the overall effect~~occurred that ~~ASU 2014–09 will have on~~would require recognition in our Condensed Consolidated Financial Statements ~~and related disclosures, our remaining efforts are primarily focused on developing controls and procedures to facilitate~~or disclosure in the ongoing process of analysis of future contracts and their terms in order to support the appropriate accounting and disclosure. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method.Notes thereto.


3.	Acquisitions and Divestitures

Acquisitions

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 our credit agreement (the “Credit Facility”). The Hunt Acquisition expanded our net leasehold position by approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford acreage.

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 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
Asset retirement obligations	356
Net assets acquired	$	98,426

Cash consideration paid to Hunt	$	84,403
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	$	98,426

Devon Acquisition

OnIn July ~~30,~~ 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”) with Devon Energy Corporation (“Devon”) to acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of ~~$205.0~~$205 million in cash ~~subject to customary purchase price adjustments~~ (the ~~“Acquisition”~~“Devon Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Devon Acquisition ~~has~~had an effective date of March 1, 2017, ~~(the “Effective Date”)~~ and closed on September 29, 2017, ~~(the “Date of Acquisition”),~~ at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. On the Date of Acquisition we also identified and applied $3.2 million of preliminary purchase price adjustments to net working capital items attributable to the period from the Effective Date through the Date of Acquisition (the “Post-Effective Period”). The $3.2 million remaining in the Escrow Account as of September 30, 2017, which is included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet, is attributable to certain properties for which title defects have been identified. To the extent that Devon is successful in curing these title defects, funds will be transferred from the Escrow Account to Devon and we will reclassify corresponding amounts from Other assets to Property and equipment, net on our Condensed Consolidated Balance Sheet.

OnIn November 1, 2017, we acquired additional working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement.

As of December 31, 2017, $3.2 million remained in the Escrow Account, which was included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet. The final settlements of the Devon Acquisition together with the tag-along rights acquisition, occurred in February 2018, at which time $2.5 million in cash was transferred from the Escrow Account to Devon, and the remaining $0.7 million was distributed to us. In addition, Devon transferred $0.4 million to us for suspended revenues attributable to the acquired properties.

The Devon Acquisition was financed with the net proceeds received from borrowings under ~~a new~~the $200 million ~~second lien credit agreement~~Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 8 for terms of the Second Lien Facility) and incremental borrowings under ~~our credit agreement (the “Credit Facility”).~~the Credit Facility.

We incurred ~~$1.5~~a total of $1.0 million of transaction costs in 2017 associated with the Devon Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our ~~“General and administrative”~~G&A expenses.

We accounted for the Devon Acquisition by applying the acquisition method of accounting as of ~~the Date of Acquisition. In accordance with the Purchase Agreement, the Acquisition is deemed to have occurred on~~ September ~~30,~~29, 2017. Accordingly, no production, revenues and expenses attributable to the Devon Properties have been included in our results of operations for the periods ended September 30, 2017. The initial accounting for the Acquisition as presented below is based upon preliminary information available to us and was not complete as of the date our Condensed Consolidated Financial Statements were issued. The final purchase price will be subject to additional post-closing adjustments for the Post-Effective Period to be identified by Devon and agreed to by us in a final settlement.

The following table represents the ~~preliminary~~final fair values assigned to the net assets acquired ~~as of~~and the ~~Date of Acquisition and the~~total consideration transferred:


Assets
Oil and gas properties - proved	$	42,795		$	42,866
Oil and gas properties - unproved	142,817			146,686
Other property and equipment	8,642			8,642
Liabilities
Asset retirement obligations (“AROs”)	491
Revenue suspense				355
Asset retirement obligations				494
Net assets acquired	$	193,763		$	197,345

Cash consideration paid to Devon on the Date of Acquisition	$	189,911
Cash consideration paid to Devon and tag-along parties, net				$	190,277
Amount transferred to Devon from the Escrow Account	7,049			9,519
Application of working capital adjustments, net	(3,197		)	(2,451		)
Preliminary purchase price	$	193,763
Total consideration transferred				$	197,345

Valuation of Acquisitions

The fair values of the oil and gas properties acquired in the Hunt and Devon Acquisitions 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 ~~(v)~~(vi) a market-based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to replacement costs for similar assets adjusted for the age and normal use of the underlying assets. 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 and Devon Acquisition have been included in our Consolidated Financial Statements for the periods after March 1, 2018 and after September 29, 2017, respectively. The Hunt Acquisition provided revenues and estimated earnings (including revenues less operating expenses and excluding allocations of interest expense and income taxes) of approximately $0.4 million and $0.2 million, respectively, for the period from March 1, 2018 through March 31, 2018. As the properties and working interests acquired in connection with the Hunt and Devon Acquisitions 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 ~~periods presented~~three and six months ended June 30, 2018 and 2017, assuming the ~~Acquisition~~Hunt and Devon Acquisitions and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the ~~Acquisition~~Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods. ~~We have excluded any pro forma presentations for the Predecessor periods as they are not comparable.~~


	Three Months			Nine Months
	Ended			Ended
	September 30,			September 30,		Three Months Ended June 30,					Six Months Ended June 30,
	2017			2017		2018			2017		2018		2017
Total revenues	$	41,865		$	130,504	$	111,580		$	51,978	$	194,036	$	99,699
Net income (loss) attributable to common shareholders	$	(8,657	)	$	38,947
Net income (loss)						$	(2,521	)	$	22,651	$	10,868	$	50,839
Net income (loss) per share - basic	$	(0.58	)	$	2.60	$	(0.17	)	$	1.51	$	0.72	$	3.39
Net income (loss) per share - diluted	$	(0.58	)	$	2.58	$	(0.17	)	$	1.51	$	0.72	$	3.37

Divestitures

Mid-Continent Divestiture

In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our remaining Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $6.0 million in cash, subject to customary adjustments. Upon the signing of the purchase and sale agreement, the buyer paid us a deposit in the amount of $0.7 million. The deposit has been reflected as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. The sale has an effective date of March 1, 2018 and closed on July 31, 2018, at which time we received proceeds of $5.5 million. The sale proceeds and de-recognition of certain assets and liabilities will be recorded as a reduction of our net oil and gas properties. A final settlement is scheduled to occur in the fourth quarter of 2018.

The properties have asset retirement obligations (“AROs”) of $0.3 million. We also had a net working capital deficit attributable to the oil and gas properties of $1.1 million as of June 30, 2018. The net pre-tax operating income attributable to the Mid-Continent assets was $0.6 million and $0.3 million for the three months ended June 30, 2018 and 2017, and $1.4 million and $0.6 million for the six months ended June 30, 2018 and 2017, respectively.

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.	Bankruptcy Proceedings and Emergence

On May 12, 2016, ~~(the “Petition Date”),~~ we and eight of our subsidiaries filed voluntary petitions (In re Penn Virginia Corporation, et al., Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”).

On August 11, 2016, ~~(the “Confirmation Date”),~~ the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates, ~~(the “Plan”),~~ and we subsequently emerged from bankruptcy on September 12, 2016 (the “Emergence Date”).

Effective January 17, 2018, the Bankruptcy Court closed the eight cases attributable to our subsidiaries, leaving the aforementioned lead case open pending the entry of a final decree or order by the Bankruptcy Court. While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until they have been appropriately discharged. As of ~~November~~August 3, ~~2017,~~2018, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of ~~Successor~~our common stock have been allocated, certain of these matters must be settled with cash payments. As of ~~September~~June 30, ~~2017,~~2018, we had $3.9 million reserved for outstanding claims to be potentially settled in cash. This reserve is included as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.

5. 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,			June 30,			December 31,
	2017			2016			2018			2017
Customers	$	30,852		$	20,489		$	55,736		$	39,106
Joint interest partners	18,938			7,238			17,834			32,493
Other	668			3,789			364			584
	50,458			31,516			73,934			72,183
Less: Allowance for doubtful accounts	(2,362		)	(2,421		)	(2,362		)	(2,362		)
	$	48,096		$	29,095		$	71,572		$	69,821

For the ~~nine~~six months ended ~~September~~June 30, ~~2017, two~~2018, three customers accounted for ~~$85.9~~$157.8 million, or approximately ~~82%~~84%, of our consolidated product revenues. The revenues generated from these customers during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018, were ~~$72.6~~$81.0 million, $41.0 million and ~~$13.3~~$35.8 million, or ~~69%~~43%, 22% and ~~13%~~19% of the consolidated total, respectively. As of ~~September~~June 30, 2018 and December 31, 2017, ~~$14.6~~$41.9 million and $32.1 million, or approximately ~~47%, of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2016, or combined Predecessor~~75% and ~~Successor periods, three customers accounted for $93.5 million, or approximately 94%, of our consolidated product revenues. The revenues generated from these customers during the~~ ~~nine months ended September 30, 2016~~ ~~were $64.1 million, $15.8 million and $13.6 million, or approximately 64%, 16% and 14% of the consolidated total, respectively. As of~~ ~~December 31, 2016, $16.7 million, or approximately 81%~~82%, 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 six months ended June 30, 2017, one customer accounted for $64.6 million, or approximately 91%, of our consolidated product revenues.

Revenue from Contracts with Customers

Adoption of ASC Topic 606

Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services.

Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote off $2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018, and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017.

The following table illustrates the impact of the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2018:



	Three Months Ended June 30, 2018
	As Determined			As Reported Under			Increase
	Under Prior GAAP			ASC Topic 606			(Decrease)
Revenues
Crude oil	$	101,716		$	101,716		$	—
Natural gas liquids	$	6,103		$	5,533		$	(570	)
Natural gas	$	3,912		$	3,912		$	—
Marketing services (included in Other revenues, net)	$	153		$	153		$	—
Operating expenses
Gathering, processing and transportation	$	5,144		$	4,574		$	(570	)
Net loss	$	(2,521	)	$	(2,521	)	$	—

	Six Months Ended June 30, 2018
	As Determined			As Reported Under			Increase
	Under Prior GAAP			ASC Topic 606			(Decrease)
Revenues
Crude oil	$	172,974		$	172,974		$	—
Natural gas liquids	$	9,495		$	8,479		$	(1,016	)
Natural gas	$	6,702		$	6,702		$	—
Marketing services (included in Other revenues, net)	$	245		$	245		$	—
Operating expenses
Gathering, processing and transportation	$	8,949		$	7,933		$	(1,016	)
Net income	$	7,774		$	7,774		$	—

Accounting Policies for Revenue Recognition and Associated Costs

Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense.

NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018, and through June 30, 2018, we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales.

Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses.

Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses.

Transaction Prices, Contract Balances and Performance Obligations

Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606, which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606.

We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.


6.	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 ~~are~~to be acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future ~~commodity~~ production. ~~At times, we also utilize option contracts.~~ 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”) crude oil and Louisiana Light Sweet (“LLS”) ~~and New York Mercantile Exchange (“NYMEX”) Henry Hub gas and~~ 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 terminated all of our pre-petition derivative contracts from March 2016 through May 2016 for $63.0 million and reduced amounts outstanding under the pre-petition credit agreement (the “RBL”) by $52.0 million. In connection with these transactions, the counterparties to the derivative contracts, which were also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the Predecessor period from January 1, 2016 through the Petition Date. Subsequent to the Petition Date, we entered into a series of new commodity derivative contracts. Accordingly, we hedged a substantial portion of our estimated future crude oil production through the end of 2019. We are currently unhedged with respect to NGL and natural gas production.

In August 2017, in anticipation of the closing of the Acquisition, we bought a series of put option contracts for 4,000 barrels of oil per day (“BOPD”) for each of the quarterly periods ending in 2018 with a strike price of $55.00 per barrel. We incurred premiums ranging from $8.00 to $9.50 per barrel which were deferred. In early October and subsequent to the closing of the Acquisition, we sold the underlying put options and converted the contracts to fixed price swaps with 1,000 BOPD for each of the quarterly periods ending in 2018 for a weighted-average WTI-based swap price of $49.00 per barrel, 1,000 BOPD for each of the quarterly periods ending in 2018 for a weighted-average swap price based on the LLS index of $50.83 per barrel and 2,000 BOPD for each of the quarterly periods in 2019 for a weighted-average swap price based on the LLS index of $50.86 per barrel. Premiums that were due upon the sale of the put option contracts were settled via a reduction in the strike price of the resulting swap contracts. We also entered into additional hedge contracts in October 2017 (see below).

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of ~~September~~June 30, ~~2017~~2018:


		Average	Weighted							Average	Weighted
		Volume Per	Average		Fair Value					Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability		Instrument	Day	Price		Asset		Liability
Crude Oil:		(barrels)	($/barrel)							(barrels)	($/barrel)
Fourth quarter 2017	Swaps	4,381	$	48.59	$	—	$	1,361
First quarter 2018	Swaps/Put option ¹	8,513	$	47.98	—		2,427
Second quarter 2018	Swaps/Put option ¹	8,484	$	47.98	—		1,971
Third quarter 2018									Swaps-WTI	10,455	$	57.05	$	—	$	14,270
Third quarter 2018	Swaps/Put option ¹	8,455	$	47.98	—		1,563		Swaps-LLS	6,000	$	65.27	—		5,605
Fourth quarter 2018	Swaps/Put option ¹	8,455	$	47.98	—		1,251		Swaps-WTI	10,455	$	57.05	—		11,332
Fourth quarter 2018									Swaps-LLS	6,000	$	65.27	—		4,418
First quarter 2019									Swaps-WTI	6,446	$	54.46	—		6,999
First quarter 2019	Swaps	2,946	$	49.87	—		356		Swaps-LLS	5,000	$	59.17	—		5,310
Second quarter 2019	Swaps	2,921	$	49.87	—		307		Swaps-WTI	6,421	$	54.48	—		6,115
Second quarter 2019									Swaps-LLS	5,000	$	59.17	—		4,568
Third quarter 2019									Swaps-WTI	6,397	$	54.50	—		5,337
Third quarter 2019	Swaps	2,897	$	49.87	—		258		Swaps-LLS	5,000	$	59.17	—		3,876
Fourth quarter 2019	Swaps	2,898	$	49.87	—		231		Swaps-WTI	6,398	$	54.50	—		4,635
Fourth quarter 2019									Swaps-LLS	5,000	$	59.17	—		3,221
First quarter 2020									Swaps-WTI	6,000	$	54.09	—		3,846
Second quarter 2020									Swaps-WTI	6,000	$	54.09	—		3,302
Third quarter 2020									Swaps-WTI	6,000	$	54.09	—		2,844
Fourth quarter 2020									Swaps-WTI	6,000	$	54.09	—		2,451
Settlements to be paid in subsequent period	Settlements to be paid in subsequent period						172		Settlements to be paid in subsequent period						4,607

~~_______________________~~

As discussed above, the put option contracts were unwound and converted to fixed price swaps in early October 2017. Including the effect of these transactions as well as additional hedge contracts entered into in October 2017, we have hedged our crude oil production as follows: remainder of 2017 - 4,381 BOPD at a weighted-average WTI-based price of $48.59 per barrel and 663 BOPD at a weighted-average LLS-based price of $56.18 per barrel, 2018 - 5,477 BOPD at a weighted-average WTI-based price of $49.30 per barrel and 1,500 BOPD at a weighted-average LLS-based price of $51.97 per barrel, 2019 - 2,915 BOPD at a weighted-average WTI-based price of $49.87 per barrel and 2,500 BOPD at a weighted-average LLS-based price of $51.30 per barrel and 2020 - 1,000 BOPD at a weighted-average WTI-based price of $50.35 per barrel.

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:

Successor Predecessor
Three Months Ended Period from September 13, 2016 Period from July 1, 2016
September 30, 2017 Through September 30, 2106 Through September 12, 2016

Derivative gains (losses) $ (12,275 ) $ (4,369 ) $ 8,934

Successor Predecessor
Nine Months Ended Period from September 13, 2016 Period from January 1, 2016
September 30, 2017 Through September 30, 2106 Through September 12, 2016

Derivative gains (losses) $ 15,802
$ (4,369 ) $ (8,333 )



	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018			2017
Derivative gains (losses)	$	(52,241	)	$	11,061	$	(71,036	)	$	28,077

The effects of derivative gains and (losses) and cash settlements ~~(except for those cash settlements attributable to the aforementioned termination transactions)~~ are reported as adjustments to reconcile net income ~~(loss)~~ 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, 2017				December 31, 2016					June 30, 2018				December 31, 2017
		Derivative		Derivative		Derivative		Derivative			Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities		Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	6,140	$	13,634	$	—	$	12,932	Derivative assets/liabilities – current	$	33	$	63,257	$	—	$	27,777
Commodity contracts	Derivative assets/liabilities – noncurrent	2,520		4,923		—		14,437		Derivative assets/liabilities – noncurrent	54		29,566		—		13,900
		$	8,660	$	18,557	$	—	$	27,369		$	87	$	92,823	$	—	$	41,677

As of ~~September~~June 30, ~~2017~~2018, we reported ~~total~~net commodity derivative ~~assets~~liabilities of ~~$8.7~~$92.7 million. The contracts associated with this position are with ~~three~~eight counterparties, all of which are investment grade financial institutions. 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.


7.	Property and Equipment

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


	September 30,			December 31,			June 30,			December 31,
	2017			2016			2018			2017
Oil and gas properties:
Proved	$	369,384		$	251,083		$	756,863		$	460,029
Unproved	147,594			4,719			134,943			117,634
Total oil and gas properties	516,978			255,802			891,806			577,663
Other property and equipment	12,484			3,575			16,105			12,712
Total properties and equipment	529,462			259,377			907,911			590,375
Accumulated depreciation, depletion and amortization	(43,402		)	(11,904		)	(116,287		)	(61,316		)
	$	486,060		$	247,473		$	791,624		$	529,059

Unproved property costs of ~~$147.6~~$134.9 million and ~~$4.7~~$117.6 million have been excluded from amortization as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, respectively. We transferred ~~$1.9~~$5.6 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~~six months ended ~~September~~June 30, ~~2017.~~2018. We capitalized internal costs of $1.6 million and $1.1 million and interest of $4.7 million and less than $0.1 million during the ~~nine~~six months ended ~~September~~June 30, 2018 and 2017, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization (“DD&A”) per barrel of oil equivalent of proved oil and gas properties was ~~$11.93~~$15.36 and $11.74 for the ~~nine~~six months ended ~~September~~June 30, 2018 and 2017, $10.04 for the Predecessor period from January 1, 2016 through September 12, 2016 and $11.09 for the Successor period from September 13, 2016 through September 30, 2016. The DD&A rate for the Predecessor period was determined under the successful efforts method while the Successor periods subsequent to September 12, 2016 were determined under the full cost method (see Note 2).respectively.


8.	Long-Term Debt

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


	September 30, 2017					December 31, 2016				June 30, 2018					December 31, 2017
	Principal			Unamortized Discount and Deferred Issuance Costs ¹		Principal		Unamortized Discount and Deferred Issuance Costs		Principal			Unamortized Discount and Deferred Issuance Costs ^{1, 2}		Principal			Unamortized Discount and Deferred Issuance Costs ^{1, 2}
Credit facility ²	$	57,000				$	25,000
Second lien term loans	200,000			$	11,945	—		$	—
Credit facility										$	243,500				$	77,000
Second lien term loan										200,000			$	10,676	200,000			$	11,733
Totals	257,000			$	11,945	25,000		$	—	443,500			$	10,676	277,000			$	11,733
Less: Unamortized discount	(4,000		)			—				(3,506		)			(3,839		)
Less: Unamortized deferred issuance costs	(7,945		)			—				(7,170		)			(7,894		)
Long-term debt, net	$	245,055				$	25,000			$	432,824				$	265,267

_______________________

¹ ~~Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method.~~


²¹	Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over ~~it’s~~its contractual term, have been presented as a component of Other assets (see Note 11) 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

On the Emergence Date, we entered into the Credit Facility. The Credit Facility ~~currently~~ provides for a ~~$237.5~~$340.0 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In ~~September 2017,~~March 2018, the borrowing base under the Credit Facility was redetermined from ~~$200~~$237.5 million to ~~$237.5~~$340.0 million pursuant to the Master Assignment, Agreement and Amendment No. 34 to the Credit Facility (the ~~“Third~~“Fourth Amendment”). In the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, we paid and capitalized issue costs of ~~$1.7~~$0.7 million in connection with the amendments that increased our borrowing base and wrote-off $0.8 million of previously capitalized issue costs due to changes in the composition of financial institutions comprising the Credit Facility bank group associated with the amendments.Fourth Amendment. 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 generally ~~redetermined~~ semi-annually 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 April 2018 redetermination was accelerated to March in connection with the Hunt Acquisition. The Credit Facility is available to us ~~to pay expenses associated with our bankruptcy proceedings and~~ for general corporate purposes, including working capital. The Credit Facility matures in September 2020. We had $0.8 million in letters of credit outstanding as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016.~~2017.

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 2.00% to 3.00%, 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 3.00% to 4.00%, 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~~June 30, ~~2017,~~2018, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was ~~4.42%~~5.58%. Unused commitment fees are charged at a rate of 0.50%.

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

The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Credit Facility (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) 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 (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter ~~initially~~ of ~~4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to~~ 3.50 to 1.00.

The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, 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~~June 30, ~~2017,~~2018, 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 $200 million Second Lien Facility. We received net proceeds of ~~$188.1~~$187.8 million from the Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of ~~$7.9~~$8.2 million. The proceeds from the Second Lien Facility were used to fund the Devon Acquisition and related fees and expenses. The maturity date under the Second Lien Facility is September 29, 2022.

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 ~~Subsidiary Guarantors.~~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 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~~June 30, ~~2017,~~2018, 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.


9.	Income Taxes

On December 22, 2017, the U.S. Congress enacted comprehensive tax legislation as part of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA makes broad and complex changes to the U.S. tax code, including but not limited to, (i) reducing the U.S. federal corporate income tax rate from 35% to 21%; (ii) allowing the immediate deduction of certain new investments in lieu of depreciation expense over time; (iii) creating a new limitation on deductible interest expense; (iv) changing rules related to use and limitations of net operating loss (“NOL”) carryforwards created in tax years beginning after December 31, 2017, and (v) repeal of the corporate alternative minimum tax (“AMT”).

We recognized a federal and state income tax expense for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 at the blended rate of ~~35.52%~~21.6%; however, the federal and state tax expense was ~~fully~~ offset by an adjustment to the valuation allowance against our net deferred tax ~~assets.~~assets along with 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 2.1%. The effect of the adjustment was to reduce our deferred tax asset to $4.8 million as of June 30, 2018. We recognized a federal income tax benefit for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 at the ~~statutory~~blended rate of ~~35%~~35.2% which was fully offset by a valuation allowance against our net deferred tax assets. 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, primarily as a result of cumulative losses.

We ~~received~~had no liability for unrecognized tax benefits as of June 30, 2018. There were no interest and penalty charges recognized during the periods ended June 30, 2018 and 2017. Tax years from 2013 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.


10.	Executive Retirement

Effective February 28, 2018, Mr. Harry Quarls retired from his position as a ~~state income tax refund~~director and Executive Chairman of ~~less than $0.1~~the Company. In connection with his retirement, we entered into a separation and consulting agreement (“Separation Agreement”) whereby Mr. Quarls will provide transition and support services to us through December 31, 2018. We paid Mr. Quarls $0.3 million for such services and a mutually agreed-upon amount for any services in excess of a minimum level established in the Separation Agreement. The Separation Agreement included a general release of claims and provided for the accelerated vesting of certain share-based compensation awards for which we recognized expense of $0.6 million during the ~~nine~~six months ended ~~September~~June 30, ~~2016.~~

We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”)2018 (see Note 15). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control that occurred upon our emergence from bankruptcy on the Emergence Date. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

~~10. Exit Activities~~

~~Prior to the Emergence Date, the Predecessor committed to a number of actions, or exit activities, the most significant of which are described below.~~

~~Reductions in Force~~

In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In 2016, we reduced our total employee headcount by 53 employees. We incurred charges of $2.0 million in connection with this action and paid a total of $1.9 million in severance and termination benefits during the nine months ended September 30, 2016. We recognized an immaterial credit adjustment to the remaining obligation of less than $0.1 million during the combined Predecessor and Successor periods ended ended September 30, 2017. There were no payments under these obligations during the nine months ended September 30, 2017.

The costs associated with ~~these reduction-in-force actions~~the Separation Agreement, including the share-based compensation charges, are included as a component of ~~our “General and administrative”~~G&A expenses in our Condensed Consolidated Statements of ~~Operations. The related obligation is included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet.~~Operation.

~~Drilling Rig Termination~~

In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated a drilling rig contract and incurred $1.3 million in early termination charges during the Predecessor period prior to the Petition Date. As this obligation represented a pre-petition liability of the Predecessor, it was discharged in connection with our emergence from bankruptcy. The vendor recovered a portion of the amount in the form of Successor common stock.

~~Firm Transportation Obligation~~

We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in that region in 2012, we no longer had production available to satisfy the commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. During the Predecessor period September 12, 2016, we paid a total of $1.1 million and recognized accretion expense of $0.3 million attributable to the underlying obligation. In connection with our emergence from bankruptcy, we rejected the underlying contract.


11.	Additional Balance Sheet Detail

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


	September 30,		December 31,		June 30,		December 31,
	2017		2016		2018		2017
Other current assets:
Tubular inventory and well materials	$	2,297	$	2,125	$	3,817	$	5,146
Prepaid expenses	818		903		1,377		1,104
	$	3,115	$	3,028	$	5,194	$	6,250
Other assets:
Deferred issuance costs of the Credit Facility	$	3,130	$	2,785	$	2,923	$	2,857
Deposit in escrow ¹	3,205		—		—		3,210
Other	2,488		2,544		33		2,440
	$	8,823	$	5,329	$	2,956	$	8,507
Accounts payable and accrued liabilities:
Trade accounts payable	$	7,275	$	9,825	$	34,582	$	22,579
Drilling costs	10,620		2,479		34,620		22,389
Royalties and revenue – related	30,184		26,116		43,862		39,287
Production, ad valorem and other taxes ²					3,827		1,275
Compensation – related	3,135		2,557		2,802		2,975
Interest	107		55		377		223
Reserve for bankruptcy claims	3,922		3,922		3,940		3,933
Other	6,993		4,743
Deposit received for divestiture of Mid-Continent properties ³					700		—
Other ²					3,272		3,520
	$	62,236	$	49,697	$	127,982	$	96,181
Other liabilities:
Asset retirement obligations	$	3,041	$	2,459	$	3,987	$	3,286
Defined benefit pension obligations	946		1,025		897		971
Postretirement health care benefit obligations	544		488		509		476
Other	100		100		100		100
	$	4,631	$	4,072	$	5,493	$	4,833

_______________________

¹ Represents the amount remaining in the ~~escrow deposit~~Escrow Account for the Devon Acquisition, which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3).


²	The amount for December 31, 2017 was reclassified from Accounts payable and accrued expenses - Other.


³	Represents the deposit paid to us related to the Mid-Continent divestiture (see Note 3).


12.	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~~June 30, ~~2017~~2018, 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, 2017										June 30, 2018
	Fair Value			Fair Value Measurement Classification							Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3		Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	6,140		$	—	$	6,140		$	—	$	33		$	—	$	33		$	—
Commodity derivative assets – noncurrent	2,520			—		2,520			—		$	54		$	—	$	54		$	—
Liabilities:
Commodity derivative liabilities – current	$	(13,634	)	$	—	$	(13,634	)	$	—	$	(63,257	)	$	—	$	(63,257	)	$	—
Commodity derivative liabilities – noncurrent	(4,923		)	—		(4,923		)	—		$	(29,566	)	$	—	$	(29,566	)	$	—


	December 31, 2016										December 31, 2017
	Fair Value			Fair Value Measurement Classification							Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3		Measurement			Level 1		Level 2			Level 3
Liabilities:
Commodity derivative liabilities – current	$	(12,932	)	$	—	$	(12,932	)	$	—	$	(27,777	)	$	—	$	(27,777	)	$	—
Commodity derivative liabilities – noncurrent	(14,437		)	—		(14,437		)	—		$	(13,900	)	$	—	$	(13,900	)	$	—

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 ~~periods~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017.

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 and LLS crude oil ~~and NYMEX Henry Hub gas~~ 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~~Level 2 input.

Non-Recurring Fair Value Measurements

In addition to the fair value measurements applied with respect to the ~~Acquisition,~~Hunt and Devon Acquisitions, 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~~Level 3 inputs.

In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Emergence Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements.


13.	Commitments and Contingencies

Gathering and Intermediate Transportation Commitments

We have long-term agreements ~~(the “Amended Agreements”)~~ with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide ~~for~~ gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation.

Republic 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 Republic through 2031 under the gathering agreement.

Under the marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil (gross) to Republic, or to any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.

Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements attributable to the MVC under the ~~Amended Agreements~~gathering and transportation agreement are as follows: ~~$2.5~~$5.3 million for the remainder of ~~2017, $10.4 million for~~ 2018, $11.7 million for 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

We have contractual commitments for three drilling ~~rigs. One rig began operations~~rigs as of June 30, 2018 with terms expiring in August 2018, September ~~2017~~2018 and ~~is subject to a six-month commitment through March 2018. A second rig began operations in October 2017~~November 2018, respectively. We also have one-year purchase commitments for the utilization of certain frac services and ~~is committed on a limited well pad-basis. A third rig is contracted to enter service in November 2017~~the purchase of certain materials for completion operations. Both the frac services and ~~is also subject to a six-month commitment through May~~materials commitments were effective January 1, 2018. We have approximately ~~$6.9~~$22.6 million of combined obligations associated with these commitments. In May 2018, we committed to a five-year lease for new corporate office facilities that will begin in August 2018. The minimum lease commitments are as follows: less than $0.1 million for 2018, $0.4 million for 2019, $0.6 million for 2020, $0.6 million for 2021, $0.6 million for 2022 and $0.6 million for 2023.

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~~June 30, ~~2017,~~2018, we continue to maintain a $0.1 million reserve for a litigation matter. As of ~~September~~June 30, ~~2017~~2018, we also had AROs of approximately ~~$3.0~~$4.0 million attributable to the plugging of abandoned wells.

14. Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for ~~nine~~the six months ended ~~September~~June 30, ~~2017:~~2018:


	December 31,					All Other		September 30,		December 31,				All Other			June 30,
	2016			Net Income		Changes ¹		2017		2017		Net Income		Changes ¹			2018
Common stock	$	150		$	—	$	—	$	150	$	150	$	—	$	1		$	151
Paid-in capital	190,621			—		2,751		193,372		194,123		—		1,857			195,980
Retained earnings (accumulated deficit)	(5,296		)	43,463		—		38,167
Retained earnings										27,366		7,774		(2,659		)	32,481
Accumulated other comprehensive income	73			—		—		73		—		—		—			—
	$	185,548		$	43,463	$	2,751	$	231,762	$	221,639	$	7,774	$	(801	)	$	228,612

_______________________

¹ Includes equity-classified share-based compensation of ~~$2.7~~$2.5 million ~~and $0.1 million from~~during the ~~receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock.~~six months ended June 30, 2018. During the ~~nine~~six months ended ~~September~~June 30, ~~2017, 12,252~~2018, 38,115 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“~~RSUs“ ),~~RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income ~~taxes.~~taxes, respectively. This also includes a write-off of $2.7 million 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 (see Note 5).


15.	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 ~~“General and administrative” expense~~G&A expenses in our Condensed Consolidated Statements of Operations.

In the Predecessor periods in 2016 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock units. All outstanding equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. We reserved 749,600 shares of ~~Successor~~ common ~~Stock~~stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of ~~298,454~~322,437 RSUs and 98,526 ~~performance restricted stock units (“PRSUs”)~~PRSUs have been granted as of ~~September~~June 30, ~~2017.~~2018.

~~The following table summarizes our share-based compensation~~We recognized $0.9 million and $0.8 million and $2.5 million and $1.7 million of expense ~~(benefit) recognized~~attributable to the RSUs and PRSUs for the ~~periods presented:~~

Successor Predecessor
Period From Period From
Three Months Ended September 13, 2016 Through July 1, 2016 Through
September 30, 2017 September 30, 2016 September 12, 2016
Equity-classified awards ¹
$ 1,013
$ —
$ 147
Liability-classified awards —
—
—
$ 1,013
$ —
$ 147

~~_______________________~~

¹ ~~Amounts~~three and six months ended June 30, 2018 and 2017, respectively. Approximately $0.6 million of the expense for the 2018 six-month period ~~from July 1, 2016 through September 12, 2016 periods have been recasted (see Note 2).~~

Successor Predecessor
Period From Period From
Nine Months Ended September 13, 2016 Through January 1, 2016 Through
September 30, 2017 September 30, 2016 September 12, 2016
Equity-classified awards $ 2,707
$ —
$ 1,511
Liability-classified awards —
—
(19 )
$ 2,707
$ —
$ 1,492

was attributable to the accelerated vesting of certain awards of our former Executive Chairman.

In the ~~nine~~six months ended ~~September~~June 30, 2018 and 2017, we granted ~~190,891~~17,456 and 148,837 RSUs to certain employees with an average grant-date fair value of ~~$48.70~~$43.43 and $51.50 per ~~RSU.~~RSU, respectively. The RSUs are being charged to expense on a straight-line basis over a range of four to five years. In the ~~nine~~six months ended ~~September~~June 30, 2018, 38,115 shares vested, net of shares withheld for income taxes.

In the six months ended June 30, 2017, we ~~also~~ granted ~~98,526~~62,675 PRSUs to members of our management. ~~The~~No PRSUs were granted during the six months ended June 30, 2018. In the six months ended June 30, 2018, 1,495 shares vested, net of shares withheld for income taxes. Previously-issued PRSUs were issued 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 grant dates 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 $0.3 million of expense attributable to the 401(k) Plan for the ~~nine~~three and six months ended ~~September~~June 30, ~~2017,~~2018, respectively, and ~~$0.4~~$0.1 million and $0.2 million for the ~~period January 1, 2016 through September 12, 2016,~~three and ~~less than $0.1 million~~six months ended June 30, 2017, respectively. The charges for the ~~period September 13, 2016 through September 30, 2016.~~401(k) Plan are recorded as a component of G&A expenses.

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 ~~nine~~three and six months ended ~~September~~June 30, ~~2017, less than $0.1 million~~2018 and 2017. The charges for ~~the period January 1, 2016 through September 12, 2016 and less than $0.1 million for the period September 13, 2106 through September 30, 2016.~~these plans are recorded as a component of “Other income (expense)” in our Condensed Consolidated Statements of Operation.


16.	Interest Expense

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

Successor Predecessor
Three Months Ended Period From September 13, 2016 Period From July 1, 2016
September 30, 2017 Through September 30, 2016 Through September 12, 2016
Interest on borrowings and related fees ¹
$ 879
$ 180
$ 1,363
Amortization of debt issuance costs²
374
38
—
Capitalized interest (51 ) —
—
$ 1,202
$ 218
$ 1,363



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Interest on borrowings and related fees	$	7,730		$	515		$	13,778		$	905
Accretion of original issue discount ¹	168			—			333			—
Amortization of debt issuance costs	680			800			1,311			988
Capitalized interest	(2,428		)	(41		)	(4,671		)	(81		)
	$	6,150		$	1,274		$	10,751		$	1,812

___________________

Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $19.3 million for the period from July 1, 2016 through September 12, 2016, including $4.4 million and $13.4 million attributableAttributable to the ~~7.25% Senior Notes due 2019 (“2019 Senior Notes”) and the 8.5% Senior Notes due 2020 (“2020 Senior Notes”).~~


²	The three months ended September 30, 2017 includes a $0.2 million write-off attributable to a change in the composition of financial institutions comprising the Credit Facility’s bank group in connection with the Third Amendment (see Note 8).

Successor Predecessor
Nine Months Ended Period From September 13, 2016 Period From January 1, 2016
September 30, 2017 Through September 30, 2016 Through September 12, 2016
Interest on borrowings and related fees ¹
$ 1,784
$ 180
$ 36,013
Amortization of debt issuance costs ²
1,362
38
22,188
Capitalized interest (132 ) —
(183 )
$ 3,014
$ 218
$ 58,018

~~___________________~~


¹	Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $66.1 million for the period from January 1, 2016 through September 12, 2016, including $15.3 million and $46.3 million attributable to the 2019 Senior Notes and the 2020 Senior Notes, respectively.

The nine months ended September 30, 2017 includes a total of $0.8 million of write-offs attributable to changes in the composition of financial institutions comprising the Credit Facility’s bank group in connection with amendments to the CreditSecond Lien Facility (see Note 8). ~~The period from January 1, 2016 through September 12, 2016 includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes.~~


17.	Earnings ~~(Loss)~~ per Share

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


	Successor						Predecessor		Three Months Ended June 30,					Six Months Ended June 30,
	Three Months Ended			Period From September 13, 2016			Period From July 1, 2016		2018			2017		2018		2017
	September 30, 2017			Through September 30, 2016			Through September 12, 2016
Net income (loss)	$	(5,947	)	$	(3,441	)	$	1,155,341
Less: Preferred stock dividends	—			—			—
Net income (loss) attributable to common shareholders – basic and diluted	$	(5,947	)	$	(3,441	)	$	1,155,341
Net income (loss) - basic and diluted									$	(2,521	)	$	21,329	$	7,774	$	49,410

Weighted-average shares – basic	14,994			14,992			89,292		15,058			14,992		15,050		14,992
Effect of dilutive securities ¹	—			—			22,166		—			58		121		105
Weighted-average shares – diluted	14,994			14,992			111,458		15,058			15,050		15,171		15,097

_______________________

~~The number of dilutive securities for the three months ended September 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.~~ For the three months ended ~~September~~June 30, ~~2017,~~2018, approximately 0.1 million of potentially dilutive securities, ~~attributable to~~represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted ~~loss~~earnings per ~~common~~ share.

Successor Predecessor Predecessor
Nine Months Ended Period From September 13, 2016 Period From January 1, 2016
September 30, 2017 Through September 30, 2016 Through September 12, 2016
Net income (loss) $ 43,463
$ (3,441 ) $ 1,054,602
Less: Preferred stock dividends ¹
—
—
(5,972 )
Net income (loss) attributable to common shareholders – basic and diluted $ 43,463
$ (3,441 ) $ 1,048,630

Weighted-average shares – basic 14,993
14,992
88,013
Effect of dilutive securities ²
69
—
36,074
Weighted-average shares – diluted 15,062
14,992
124,087

~~_______________________~~


¹	Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the period from January 1, 2016 through September 12, 2016, as their assumed conversion would have been anti-dilutive.

² ~~The number of dilutive securities for the three and nine months ended September 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method.~~

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 ~~the recently~~ completed ~~acquisition,~~acquisitions, including our ability to realize ~~its~~their expected benefits;

potential adverse effects of the completed Chapter 11, or bankruptcy, proceedings on our liquidity, results of operations, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy;

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;

our post-bankruptcy capital structure and the adoption of Fresh Start Accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;

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 impact of our review of strategic options and any resulting potential transaction, including our ability to execute, market reactions, costs and focus from management;

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

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

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

operations;

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

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

our ability to contract for drilling rigs, frac crews, 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 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 natural gas reserves;

drilling and operating risks;

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;~~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 ~~hurricanes and~~ force majeure events;

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

~~counterparty risk related to the ability~~our reliance on a limited number of ~~these parties to meet their future obligations;~~customers and a particular region for a majority of our revenues and production;

compliance with and changes in governmental regulations or enforcement practices, especially with respect to

environmental, health and safety matters;

the implementation and impact of the Tax Cuts and Jobs Act;

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 periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017.

Additional information concerning these and other factors can be found in our press releases and public ~~periodic~~ filings with the Securities and Exchange Commission. 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 June 30, 2018 or 2017, 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 primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale, or the Eagle Ford, in Gonzales, Lavaca and DeWitt Counties in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash.

~~While crude~~Crude oil prices have ~~recovered somewhat from recent historically low levels~~continued in a steadily rising trend that began in the second half of ~~less than $30 per barrel,~~2017 throughout the six months ended June 30, 2018 and into the mid-summer season. Because of the proximity of our operating region to the Gulf Coast markets, we sell substantially all of our crude oil production based on the Light Louisiana Sweet, or ~~Bbl, in February 2016, they remain generally depressed due to domestic and global supply and demand factors~~LLS, price index. The LLS index has exceeded that of the West Texas Intermediate, or WTI, price index, providing us with a strong revenue stream compared to certain of our domestic peers and competitors further inland. With the ~~period from 2009 through 2014 when~~improved pricing environment, domestic production has increased, including that in the broader Eagle Ford region in which we ~~initially began~~operate. This environment has expanded opportunities in our ~~expansion into~~principal operating region. Furthermore, many exploration and production companies that experienced financial difficulties similar to us during the 2015 and 2016 time frame have restructured and refocused their financial resources and operating plans to capitalize on current opportunities. In addition, there has been a consolidation of holdings within the Eagle ~~Ford. Similarly, the costs~~Ford, including our own, through recent acquisitions. Collectively, these and other factors have led to higher pricing for ~~drilling, completion and general~~certain oilfield products and services, ~~have declined as the industry experienced reduced demand for such products and services. While certain of these costs remain at low levels, other costs,~~ including ~~those for~~ drilling and completion services, ~~have steadily risen as industry drilling activity continues~~which we expect to ~~recover and expand.~~continue in the intermediate term.

As discussed in ~~Note~~further detail in Notes 2 ~~to our Condensed Consolidated Financial Statements, we adopted~~ and began applying the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings, or Fresh Start Accounting on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes prior to that date. To facilitate the discussion and analysis of our financial condition and results of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. Furthermore, our presentations herein include a “black line” division, where applicable, to delineate the lack of comparability between the Predecessor and Successor. In order to further facilitate our discussion, we have addressed the Successor and Predecessor periods discretely and have provided comparative analysis, to the extent that it is practical, where appropriate. In addition, and as referenced in Note 25 to the Condensed Consolidated Financial Statements, we have adopted two new accounting standards: Accounting Standards Codification Topic 606, Revenues from Contracts with Customers, or ASC Topic 606, and Accounting Standards Update 2017–07, Improving the ~~full cost method~~Presentation of ~~accounting for our oil~~Net Periodic Pension Cost and ~~gas properties~~Net Periodic Postretirement Benefit Cost, or ASU 2017–07, effective ~~with our~~January 1, 2018. The adoption of ~~Fresh Start Accounting.~~these standards impacts the presentation and comparability of (i) NGL product revenues and Gathering, processing and transportation, or GPT, expense and (ii) General and administrative, or G&A, expenses and Other income (expense), net. We adopted ASC Topic 606 utilizing the cumulative effect transition method. Accordingly, our ~~results of operations, financial position~~NGL revenues and ~~cash flows~~GPT expense for the ~~Successor~~three and six months ended June 30, 2017 are not comparable to the 2018 presentation of these items. Our discussion and analysis of these items in the Results of Operations that follow address the effects of changes directly attributable to the adoption of ASC Topic 606. We adopted ASU 2017–07 utilizing the modified retrospective method. Accordingly, certain benefits costs that were previously reported as a component of G&A are being reported as a component of Other, net (expenses), as required by ASU 2017–07, for all periods ~~will be substantially different from our historic trends.~~presented.

The following summarizes our key operating and financial highlights for the three months ended ~~September~~June 30, ~~2017~~2018, with comparison to the three months ended ~~June 30, 2017.~~March 31, 2018. The year-over-year highlights are addressed in further detail in the discussions for Financial Condition and Results of Operations ~~and~~ ~~Financial Condition~~that ~~follow:~~follow.

Production ~~declined~~increased approximately ~~seven~~39 percent to ~~864~~2,020 thousand barrels of oil equivalent, or MBOE, from ~~925~~1,453 MBOE due primarily to ~~anticipated staging delays~~a greater number of wells turned to sales, as well as the effect of a full quarter of production from increased working interests in ~~our drilling program that were exacerbated by Hurricane Harvey, mechanical issues~~wells associated with ~~our previously-contracted drilling rigs~~the acquisition of certain oil and ~~production curtailments attributable to~~gas assets from Hunt Oil Company, or Hunt, in March 2018, or the ~~storm.~~Hunt Acquisition.

Product revenues ~~declined~~increased approximately ~~five~~44 percent to ~~$34.3~~$111.2 million from ~~$36.3~~$77.0 million due primarily to ~~lower~~33 percent higher crude oil volume and seven percent higher crude oil prices. Higher NGL and natural gas revenues from 53 percent higher volumes and 15 percent higher NGL pricing were partially offset by ~~higher~~10 percent lower natural gas ~~volumes and higher pricing for all commodity products.~~pricing.

Production and lifting costs ~~declined~~(consisting of Lease operating expenses, or LOE, and GPT) increased on an absolute basis to ~~$7.6~~$13.3 million from ~~$7.9~~$10.7 million, but ~~increased~~declined on a per unit basis to ~~$8.85~~$6.58 per barrel of oil equivalent, or BOE, from ~~$8.58~~$7.33 per BOE due primarily to the ~~decrease~~increase in production ~~volume.~~volume in the second quarter of 2018.

Production and ad valorem taxes ~~declined on an absolute and per unit basis to $1.7 million and $1.93 per BOE from $2.1 million and $2.29 per BOE, respectively, due to lower production and adjustments to ad valorem tax assessments.~~

~~General and administrative expenses~~ increased on an absolute and per unit basis to ~~$7.0~~$5.8 million and ~~$8.04~~$2.87 per BOE from ~~$3.7~~$4.1 million and ~~$4.03~~$2.82 per BOE, respectively, due to higher production volume and higher crude oil and NGL pricing.

G&A expenses decreased on an absolute and per unit basis to $5.3 million and $2.63 per BOE from $6.5 million and $4.45 per BOE, respectively, due primarily to ~~$1.5 million~~the effect of higher production volume in the second quarter of 2018 and certain acquisition transaction and executive-retirement-related costs ~~associated with~~that were incurred the ~~Acquisition, $0.2 million~~first quarter of ~~costs incurred to complete an upgrade of our ERP system and~~2018 partially offset by higher ~~compensation and~~ employee-related support costs in the second quarter as we have expanded our employee base commensurate with our current growth ~~plans as well as~~plans.

Depreciation, depletion and amortization, or DD&A, increased on an absolute and per unit basis to $31.3 million and $15.48 per BOE from $22.1 million and $15.20 per BOE, respectively, due primarily to higher production volume and the ~~effect~~effects of ~~lower production volume.~~higher drilling and completion costs and property costs from the Hunt Acquisition.

~~Our operating~~Operating income ~~declined~~increased to ~~$7.5~~$55.9 million ~~for the three months ended September 30, 2017 compared~~from $33.9 million due to ~~$11.4 million for the three months ended June 30, 2017 due~~ 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:


	Successor												Predecessor
	Three Months			Three Months			Nine Months			September 13			July 1			January 1
	Ended			Ended			Ended			through			through			through			Three Months Ended									Six Months Ended
	September 30,			June 30,			September 30,			September 30,			September 12,			September 12,			June 30,			March 31,			June 30,			June 30,
	2017			2017			2017			2016			2016			2016			2018			2018			2017			2018			2017
Total production (MBOE)	864			925			2,644			183			796			3,346			2,020			1,453			925			3,473			1,779
Average daily production (BOEPD)	9,396			10,159			9,683			10,145			10,752			13,071			22,200			16,145			10,159			19,189			9,829
Crude oil production (MBbl)	627			685			1,920			127			547			2,311			1,498			1,127			685			2,625			1,293
Crude oil production as a percent of total	73		%	74		%	73		%	70		%	69		%	69		%	74		%	78		%	74		%	76		%	73		%
Product revenues	$	34,333		$	36,274		$	105,325		$	6,316		$	26,961		$	93,649		$	111,161		$	76,994		$	36,274		$	188,155		$	70,992
Crude oil revenues	$	29,963		$	32,351		$	92,387		$	5,508		$	23,392		$	81,377		$	101,716		$	71,258		$	32,351		$	172,974		$	62,424
Crude oil revenues as a percent of total	87		%	89		%	88		%	87		%	87		%	87		%	92		%	93		%	89		%	92		%	88		%
Realized prices:
Crude oil ($ per Bbl)	$	47.78		$	47.25		$	48.12		$	43.35		$	42.75		$	35.21		$	67.89		$	63.23		$	47.25		$	65.89		$	48.29
NGLs ($ per Bbl)	$	19.19		$	15.59		$	17.98		$	12.56		$	12.66		$	11.37
NGLs ($ per Bbl) ¹																			$	20.54		$	17.94		$	15.59		$	19.56		$	17.38
Natural gas ($ per Mcf)	$	2.92		$	2.88		$	2.96		$	2.73		$	2.72		$	2.06		$	2.58		$	2.87		$	2.88		$	2.70		$	2.98
Aggregate ($ per BOE)	$	39.72		$	39.24		$	39.84		$	34.59		$	33.89		$	27.99		$	55.02		$	52.99		$	39.24		$	54.17		$	39.90
Prices adjusted for derivatives:
Crude oil ($ per Bbl)	$	49.04		$	46.57		$	47.25		$	43.35		$	44.68		$	55.98		$	59.61		$	56.51		$	46.57		$	58.28		$	46.39
Aggregate ($ per BOE)	$	40.63		$	38.73		$	39.21		$	34.59		$	35.21		$	42.33		$	48.89		$	47.77		$	38.73		$	48.42		$	38.52
Production and lifting costs:
Lease operating ($ per BOE)	$	6.07		$	5.81		$	5.88		$	4.13		$	5.29		$	4.67		$	4.32		$	5.02		$	5.81		$	4.61		$	5.78
Gathering, processing and transportation ($ per BOE)	$	2.77		$	2.77		$	2.84		$	3.15		$	6.00		$	3.96
Gathering, processing and transportation ($ per BOE) ¹																			$	2.26		$	2.31		$	2.76		$	2.28		$	2.87
Production and ad valorem taxes ($ per BOE)	$	1.93		$	2.29		$	2.18		$	2.05		$	0.72		$	1.04		$	2.87		$	2.82		$	2.29		$	2.85		$	2.30
General and administrative ($ per BOE) ¹	$	8.04		$	4.03		$	5.60		$	8.07		$	8.67		$	11.64
Depreciation, depletion and amortization ($ per BOE) ²	$	12.32		$	11.99		$	11.93		$	11.09		$	10.09		$	10.04
Cash provided by operating activities ³	$	14,277		$	26,875		$	50,294		$	3,580		$	(15,526	)	$	30,247
Cash paid for capital expenditures	$	24,261		$	25,842		$	67,844		$	—		$	784		$	15,359
General and administrative ($ per BOE) ²																			$	2.63		$	4.45		$	4.00		$	3.40		$	4.39
Depreciation, depletion and amortization ($ per BOE)																			$	15.48		$	15.20		$	11.97		$	15.36		$	11.74
Capital expenditure program costs ³																			$	125,035		$	84,228		$	25,037		$	209,263		$	44,796
Cash provided by operating activities ⁴																			$	81,736		$	38,682		$	26,875		$	120,418		$	36,017
Cash paid for capital expenditures ⁵																			$	123,511		$	77,839		$	25,842		$	201,350		$	43,583
Cash and cash equivalents at end of period				$	10,105		$	7,487		$	13,994					$	31,414		$	11,521		$	7,319		$	10,105		$	11,521		$	10,105
Debt outstanding at end of period, net				$	37,000		$	245,055		$	54,350					$	1,187,553		$	432,824		$	383,766		$	37,000		$	432,824		$	37,000
Credit available under credit facility at end of period ⁴				$	162,245		$	179,745		$	72,883					$	—
Credit available under credit facility at end of period																			$	95,745		$	144,245		$	162,245		$	95,745		$	162,245
Net development wells drilled and completed	5.0			3.0			11.6			—			—			2.9			16.9			10.0			3.0			26.9			6.6

^{__________________________________________________________________________________}


¹	The effects of the adoption of ASC Topic 606, if applied to the periods ended in 2017, would have resulted in realized prices for NGLs of $13.02 and $14.65 per BOE and GPT of $2.40 and $2.49 per BOE for the three and six months ended June 30, 2017, respectively.

Includes combined amounts of ~~$3.15~~$0.46, $1.55 and ~~$0.92~~$0.91 per BOE for the ~~three-month periods~~three months ended ~~September~~June 30, 2018, March 31, 2018 and June 30, 2017, ~~$1.67~~respectively, and $0.92 and $0.94 per BOE for the ~~nine~~six months ended ~~September~~June 30, ~~2017, $0.10 per BOE for the period from September 13 through September 30, 2016, $3.61 per BOE for the period from July 1 through September 12, 2016~~2018 and ~~$6.98 per BOE for the period from January 1 through September 12, 2016,~~2017, respectively, attributable to equity-classified ~~share-based compensation, liability-classified~~ share-based compensation and significant special charges, including ~~strategic~~acquisition and ~~financial advisory~~divestiture transaction and other costs, ~~incurred prior to our bankruptcy filing, among others,~~ as described in the discussion of “Results of Operations - General and Administrative” that follows.


²	~~Determined using the full cost method for the Successor periods and the successful efforts method for the Predecessor periods.~~

Includes ~~cash received from derivative settlements of $0.8 million, $1.1 million~~amounts accrued and ~~$48.0 million for the three-month period ended September 30, 2017, the period from July 1, 2016 through September 12, 2016~~excludes capitalized interest and the period from January 1, 2016 through September 12, 2016, respectively. Includes cash paid for derivative settlements of $0.5 million and $1.7 million for the three-month period ended June 30, 2017 and nine-month period ended September 30, 2017.capitalized labor.

⁴

AsIncludes cash paid for derivative settlements of ~~September 12, 2016, we were unable to draw on our pre-petition credit facility, or RBL.~~$12.4 million, $7.6 million and $0.5 million for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, respectively, and $20.0 million and $2.5 million for the six months ended June 30, 2018 and 2017, respectively. Reflects changes in operating assets and liabilities of $11.4 million, $(7.4) million and $4.2 million for the the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, respectively, and $4.0 million and $(6.5) million for the six months ended June 30, 2018 and 2017, respectively.


⁵	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:

~~Changes~~Initiative to ~~Executive Management~~Evaluate Strategic Alternatives

As previously reported on a Current Report on Form 8-K on August 17, 2017, effective August 15, 2017, our board of directors appointed John Brooks as our President and Chief Executive Officer and as a member of our board of directors. At that time, the board also appointed Harry Quarls as an officer of the Company in the newly created position as Executive Chairman. Mr. Quarls will continue to serve as chairman of the board.

~~Acquisition of Producing Properties~~

On July ~~30, 2017,~~23, 2018, we ~~entered into~~announced that the Board of Directors intends to evaluate a ~~purchase and~~range of strategic alternatives to enhance shareholder value, including without limitation, a corporate sale, ~~agreement,~~merger or other business combination, one or more strategic acquisitions, or other transactions. There is no assurance that the ~~Purchase Agreement, with Devon Energy Corporation, or Devon, to acquire all of Devon’s right, title and interest~~evaluation process will result in and to certain oil and gas assets, or the Devon Properties, including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205.0 million in cash, subject to customary purchase price adjustments, or the Acquisition. Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account, or the Escrow Account. The Acquisition has an effective date of March 1, 2017, or the Effective Date, andclosed on September 29, 2017, or the Date of Acquisition, at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. On the Date of Acquisition we also identified and applied $3.2 million of preliminary purchase price adjustments to net working capital items attributable to the period from the Effective Date through the Date of Acquisition, or the Post-Effective Period. The $3.2 million remaining in the Escrow Account as of September 30, 2017, which is included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet, is attributable to certain properties for which title defects have been identified. To the extent that Devon is successful in curing these title defects, funds will be transferred from the Escrow Account to Devontransaction, and we will ~~reclassify corresponding amounts from Other assets to Property and equipment, net on our Condensed Consolidated Balance Sheet.~~

~~On November 1, 2017, we acquired~~incur additional ~~working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement.~~

~~We incurred $1.5 million of transaction costs associated with the Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized~~expenses as a ~~component~~result of ~~our “General and administrative” expenses.~~

In accordance with the Purchase Agreement, the Acquisition is deemed to have occurred on September 30, 2017. Accordingly, no production, revenues or expenses attributable to the Devon Properties have been included in our results of operations for the periods ended September 30, 2017. The final purchase price will be subject to additional post-closing adjustments for the Post-Effective Period to be identified by Devon and agreed to by us in a final settlement.

As the Devon Properties include increases in working interests of many properties for which we are the operator as well as other properties that are contiguous to our existing asset base in South Texas, the Acquisition represents an important step in our long-term strategy of profitably growing our production and reserves. The Devon Properties include a substantial number of drilling locations in the lower Eagle Ford formation including several identified for extended reach laterals. Beyond the superior economics that we have experienced associated with drilling longer reach laterals, complimented by higher working interests, we also look forward to testing the upper Eagle Ford and Austin Chalk. We plan to begin drilling on the Devon Properties in the first quarter of 2018.

~~Effects of Hurricane Harvey~~

In late August 2017, southeast Texas was adversely impacted by Category 4 Hurricane Harvey. While we experienced no long-term damage to our producing assets or facilities in that region, our production, drilling and completion operations were all curtailed for several days at the end of August 2017. Sales of production were initially curtailed to approximately 50 percent of full potential due to compression availability and localized flooding and were brought back online to full potential in early September 2017. Additionally, drilling operations were suspended at the four-well Rhino pad and the three-well Oryx pad and completion operations were suspended at the eight-well Chicken Hawk and Jake Berger pads in advance of the storm.this evaluation process.

Production and Development Plans

Total production for the ~~third~~second quarter of ~~2017~~2018 was ~~864~~2,020 MBOE, or ~~9,396~~22,200 barrels of oil equivalent per day, or BOEPD, with approximately 7374 percent, or ~~627~~1,498 MBOE, of production from crude oil, 1413 percent from NGLs and 13 percent from natural gas. Production from our Eagle Ford operations during this period was ~~785~~1,952 MBOE or ~~8,535~~21,450 BOEPD. Approximately 7876 percent of our Eagle Ford production for the period was from crude oil, 1213 percent was from NGLs and 1011 percent was from natural gas. Production from our Eagle Ford operations was approximately 9197 percent of total Company production during the ~~third~~second quarter of ~~2017.~~

2018.

We drilled and turned ~~seven~~20 gross ~~(five~~(16.9 net) Eagle Ford wells to sales during the ~~third~~second quarter of 2018. Subsequent to June 30, 2018, we drilled and turned an additional two gross (1.7 net) wells from the Hawn Holt pad to sales. As of August 3, 2018, we were drilling six gross (5.1 net) wells with our three operated drilling rigs, four gross (3.9 net) wells were completing ~~operations~~and one gross (1.0 net) well was waiting on ~~our Chicken Hawk and Jake Berger pads. Our average working interest~~completion.

As of August 3, 2018, we had approximately 97,900 gross (84,060 net) acres in the ~~Chicken Hawk and Jake Berger pads are approximately 76~~Eagle Ford, net of expirations. Approximately 92 percent ~~and 64 percent, respectively.~~

~~During the third quarter of 2017, our drilling operations were significantly impacted by mechanical issues on both~~ of our ~~previously-contracted drilling rigs.~~acreage is held by production and substantially all is operated by us.

Acquisition of Producing Properties

In December 2017, we entered into a purchase and sale agreement with Hunt to acquire certain oil and gas assets in the Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, Texas for $86.0 million in cash, subject to adjustments. The ~~associated downtime resulted~~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 ~~delays~~certain wells that we previously drilled as operator, and ~~contributed~~in which Hunt had rights to ~~drilling shorter than expected laterals for several of our horizontal wells. Both of these drilling rigs have been released and we recently contracted three flex rigs from a new vendor (see Note 13~~participate prior to the ~~Condensed Consolidated Financial Statements). In addition, the impact~~transaction closing. Accumulated costs, net of ~~Hurricane Harvey resulted in delays to our planned drilling schedule~~suspended revenues for these wells was $13.8 million, which we have reflected as ~~discussed above.~~

We have completed frac operations on the four-well Rhino Hunter pad. Frac operations have commenced on the three-well Oryx Hunter pad and we expect to turn these three wells to sales in late November 2017. Twoa component of the ~~new rigs are currently drilling wells on the Furrh pad located~~total net assets acquired. The Hunt Acquisition expanded our net leasehold position by approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford ~~acreage and the Geo Hunter pad located in the southeastern portion of our Eagle Ford~~ acreage. The third rig has begun mobilization and is expected to begin drilling on the Schacherl-Effenberger pad located in the southeastern portion of our Eagle Ford acreage by mid-November 2017. A total of six wells on the three pads are expected to be drilled by the end of 2017, with completion operations anticipated to commence immediately following drilling operations.

Based on our revised drilling and completion schedule for the remainder of 2017, we anticipate total capital expenditures for 2017 to total between $120 and $140 million with approximately 95 percent of capital being directed to drilling and completions in the Eagle Ford.

During the quarter ended September 30, 2017, we added 19,600 net acres through the Acquisition and leased more than 300 incremental acres, net of expirations, thereby increasing our core net acreage position in the volatile window of the lower Eagle Ford to approximately 75,800 net acres. Approximately 92 percent of our core acreage is held by production. We currently operate 359 gross (271.9 net) wells and have working interests in 45 gross (14.2 net) outside-operated wells in the Eagle Ford as of November 3, 2017. We currently have two wells drilling and seven completing or waiting on completion.

~~Amendment to Credit Facility and Borrowing Base Redetermination~~

On September 29, 2017 and in connection with the closing of our new $200 million second lien credit agreement, or the Second Lien Facility (discussed below), we entered into the Master Assignment, Agreement and Amendment No. 3, or the Third Amendment, to our Credit Facility to, among other things, provide for the entry into the Second Lien Facility, the borrowings thereunder, the granting of liens to secure the obligations thereunder and other related modifications. In addition, pursuant to the Third Amendment, the borrowing base under the Credit Facility was increased to $237.5 million from $200 million.

~~Second Lien Credit Facility~~

On September 29, 2017, we entered into the Second Lien Facility. We received net proceeds of $188.1 million from the Second Lien Facility net of an original issue discount, or OID, of $4.0 million and issue costs of $7.9 million. The proceeds from the Second Lien Facility were used to fund the Acquisition and related fees and expenses. The Second Lien Facility was issued at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.8578%. The initial interest rate on the Second Lien Facility as described above was based on the three-month LIBOR rate in effect on the date the Second Lien Facility was entered into. The maturity date under the Second Lien Facility is September 29, 2022.

Commodity Hedging Program

As of ~~November~~August 3, ~~2017, including the effect of additional hedge contracts that we entered into or otherwise modified in October 2017,~~2018, we have hedged a ~~substantial~~ portion of our estimated future crude oil production through the end of ~~2020. For the remainder of 2017, we have 4,381 BOPD hedged~~2020 with a ~~weighted-average swap price~~mix of ~~$48.59 per barrel based on the West Texas Intermediate, or WTI, index~~WTI- and 663 BOPD with a weighted-average swap price of $56.18 per barrel based on the Light Louisiana Sweet, or LLS, index. For 2018, we have 5,477 BOPD with a weighted-average WTI-based swap price of $49.30 per barrel and 1,500 BOPD with a weighted-average LLS-based swap price of $51.97 per barrel. For 2019, we have 2,915 BOPD with a weighted-average WTI-based swap price of $49.87 per barrel and 2,500 BOPD with a weighted-average LLS-based swap price of $51.30 per barrel. For 2020, we have 1,000 BOPD with a weighted-average WTI-based swap price of $50.35 per barrel.LLS- indexed swaps. We are currently unhedged with respect to NGL and natural gas production. The following table summarizes our hedge positions for the periods presented:



	WTI Volumes	WTI Average Swap Price		LLS Volumes	LLS Average Swap Price
	(Barrels per day)	($ per barrel)		(Barrels per day)	($ per barrel)
Remainder of 2018	10,455	$	57.05	6,000	$	65.27
2019	6,415	$	54.48	5,000	$	59.17
2020	6,000	$	54.09	—	—

Divestiture of Mid-Continent Properties

In June 2018, we entered into a purchase and sale agreement with a third party to sell all of our remaining Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $6 million in cash, subject to customary adjustments. We received a deposit of $0.7 million in June 2018. The sale has an effective date of March 1, 2018, and closed on July 31, 2018, at which time we received proceeds of $5.5 million.

Financial Condition

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to ~~$237.5~~$340 million in borrowing commitments. The current borrowing base under the Credit Facility is also ~~$237.5~~$340 million. As of ~~November~~August 3, ~~2017,~~2018, we had ~~outstanding borrowings and letters of credit of $61.0~~$71.7 million ~~and $0.8 million, respectively, resulting in $175.7 million of availability~~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. 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. In order to mitigate this volatility, we entered into derivative contracts ~~in May 2016 and at various times in 2017~~ hedging a ~~substantial~~ portion of our estimated future crude oil production through the end of 2020.

Capital Resources

Under our ~~business plan,~~capital program for 2018, we ~~currently~~ anticipate capital expenditures, excluding ~~the Acquisition,~~acquisitions, to total between ~~$120~~$390 million and ~~$140~~$410 million for ~~2017,~~2018 with approximately 9596 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our ~~2017~~2018 capital spending with cash from operating activities and borrowings under the Credit Facility. Based upon current price and production expectations for ~~2017,~~2018, we believe that our cash from operating activities and borrowings under our Credit Facility will be sufficient to fund our operations through year-end ~~2017;~~2018; 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. ~~Our 2017 capital expenditure budget does not allocate any funds for acquisitions.~~ 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~~August 3, ~~2017,~~2018, we had approximately $4$9.4 million of cash on hand. In addition to commodity price volatility, as discussed above, our cash from operating activities is impacted by the timing of our working capital requirements. The most significant component is drilling and completion capital expenditures and the related billing and collection of our partners’ shares thereof. This component can be substantial to the extent that we are the operator of lower working interest wells. In certain circumstances, we have and will continue to utilize capital cash calls to mitigate the burden on our working capital. For additional information and an analysis of our historical cash from operating activities, see the “Cash Flows” discussion that follows.

Credit Facility Borrowings. ~~We initially~~During the three and six-months ended June 30, 2018, we borrowed ~~$75.4~~$48.5 million and $166.5 million, respectively, under the Credit Facility, ~~upon our emergence from bankruptcy in September 2016. Since that time we have paid down $14.4 million, net~~with a substantial portion borrowed during the first quarter of ~~new borrowings through November 3, 2017.~~2018 to fund the Hunt Acquisition. 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 ~~period~~periods presented:

Borrowings Outstanding

Weighted-
Average
Maximum
Weighted-
Average Rate
Three months ended September 30, 2017 $ 43,231
$ 57,000
4.28 %
Nine months ended September 30, 2017 $ 39,455
$ 57,000
4.15 %



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended June 30, 2018	$	224,370	$	243,500	5.44	%
Six months ended June 30, 2018	$	179,939	$	243,500	5.28	%

Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-strategic undeveloped acreage, among others. For additional information and an analysis of our historical proceeds from sales of assets, see the “Cash Flows” discussion that follows.

Capital Market 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:


	Successor						Predecessor
	Nine Months			September 13			January 1
	Ended			Through			Through			Six Months Ended
	September 30,			September 30,			September 12,			June 30,			June 30,
	2017			2016			2016			2018			2017
Cash flows from operating activities
Operating cash flows, net of working capital changes	$	54,272		$	4,782		$	34,731		$	150,502		$	40,171
Crude oil derivative settlements (paid) received, net	(1,670		)	—			48,008
Crude oil derivative settlements paid, net										(19,977		)	(2,458		)
Interest payments, net of amounts capitalized	(1,596		)	—			(4,148		)	(8,953		)	(795		)
Income tax refunds	—			—			35
Acquisition transaction costs paid	(712		)	—			—
Strategic, financial and bankruptcy-related advisory fees and costs paid	—			—			(46,606		)
Restructuring and exit costs paid	—			(1,202		)	(1,773		)
Acquisition and divestiture transaction costs paid										(462		)	—
Bankruptcy-related administration fees and costs paid										(442		)	(901		)
Consulting costs paid to former Executive Chairman										(250		)	—
Net cash provided by operating activities	50,294			3,580			30,247			120,418			36,017
Cash flows from investing activities
Acquisition, net	(200,162		)	—			—
Acquisitions, net										(86,835		)	—
Capital expenditures	(67,844		)	—			(15,359		)	(201,350		)	(43,583		)
Proceeds from sales of assets, net	—			—			224			2,525			—
Other, net	—			—			1,186
Net cash used in investing activities	(268,006		)	—			(13,949		)	(285,660		)	(43,583		)
Cash flows from financing activities
Proceeds (repayments) from credit facility borrowings, net	32,000			(21,000		)	(43,771		)
Proceeds from second lien facility, net	196,000			—			—
Proceeds from credit facility borrowings, net										166,500			12,000
Debt issuance costs paid	(9,562		)	—			(3,011		)	(754		)	(1,090		)
Proceeds received from rights offering, net	55			—			49,943			—			55
Other, net	(55		)	—			—			—			(55		)
Net cash provided by (used in) financing activities	218,438			(21,000		)	3,161
Net increase (decrease) in cash and cash equivalents	$	726		$	(17,420	)	$	19,459
Net cash provided by financing activities										165,746			10,910
Net increase in cash and cash equivalents										$	504		$	3,344

Cash Flows from Operating Activities. The ~~overall~~ increase in net cash from operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 compared to the corresponding period ~~from the combined Successor and Predecessor periods~~ in ~~2016~~2017 was primarily attributable toto: (i) higher ~~pricing resulting in higher overall product revenue receipts~~production volume in the ~~2017~~2018 period, (ii) ~~substantially~~incremental net operating cash inflows from the Hunt Acquisition and the 2017 acquisition of oil and gas assets from Devon Energy Corporation, or the Devon Acquisition, (iii) higher ~~payments~~crude oil pricing in the 2016 Predecessor period for professional fees and other costs associated with our bankruptcy proceedings and consideration of strategic financing alternatives in advance thereof, (iii) payments for termination benefits and other exit activities in the 2016 Predecessor2018 period and (iv) lower payments in the 2018 period for bankruptcy-related administration costs. These items were partially offset by: (i) higher settlements paid for crude oil derivatives, (ii) higher interest payments due to ~~lower~~greater outstanding borrowings ~~under the Credit Facility~~ in the ~~2017~~2018 period, ~~as compared to outstanding borrowings under the RBL~~(iii) transaction costs paid in the 2016 Predecessor period. These increases were partially offset by the effect of the payment of cash settlements from derivatives in 2017 compared to the receipt of net settlements during the Predecessor2018 period in 2016. Specifically, our hedged prices for maturing contracts have exceeded the WTI crude oil prices on our post-petition derivatives resulting in net payments in the 2017 period while the opposite situation occurred in the Predecessor period in 2016 resulting in receipt of cash settlements as well as the early termination of certain pre-petition derivative contracts in the Predecessor period in 2016 which accelerated the receipt of cash settlements. In addition, we (i) paid certain transaction costs associatedconnection with the ~~Acquisition~~Hunt and Devon Acquisitions and the Mid-Continent divestiture and (iv) certain costs paid in connection with the ~~2017 period and (ii) experienced higher working capital utilization in 2017 as a result of the restart~~retirement of our ~~drilling program, which had been suspended~~Executive Chairman in February ~~2016.~~2018.

Cash Flows from Investing Activities. In the ~~2017~~2018 period, we paid a combined total of ~~$200.2~~$87.9 million for the ~~Acquisition which included $189.9 million paid to Devon on the Date of~~Hunt Acquisition and ~~$10.3~~the purchase of other working interests in producing properties in the Eagle Ford and received a total of $1.1 million ~~paid into~~in connection with the ~~Escrow Account in July 2017.~~final settlement of the Devon Acquisition. As illustrated in the tables below, our cash payments for capital expenditures were substantially higher during the 2018 period as compared to the 2017 period, due primarily to the employment of three drilling rigs and a second frac spread in our current drilling program as opposed to two drilling rigs and one frac spread during the 2017 period as ~~compared~~well as the effect of higher working interests from the Hunt and Devon Acquisitions. In addition, we received proceeds of $1.8 million in the 2018 period attributable to the ~~combined Successor and Predecessor periods in 2016 due primarily to the restart of our Eagle Ford drilling program. Furthermore, the cash paid for capital expenditures~~sales of: (i) undeveloped acreage holdings in the ~~Predecessor period~~Tuscaloosa Marine Shale in ~~2016 includes~~Louisiana, (ii) certain undeveloped deep leasehold rights in Oklahoma, (iii) certain pipeline assets in our former Marcellus Shale operating region and (iv) scrap tubular and well materials. We also received a ~~higher portion attributable to settlements~~deposit of ~~accrued capital charges from~~$0.7 million in June 2018 in connection with the ~~prior year-end period. The Predecessor period in 2016 also includes insurance recoveries from a casualty loss incurred in 2015.~~Mid-Continent divestiture.

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


	Successor					Predecessor
	Nine Months			September 13		January 1
	Ended			Through		Through			Six Months Ended
	September 30,			September 30,		September 12,			June 30,		June 30,
	2017			2016		2016			2018		2017
Drilling and completion	$	72,263		$	—	$	3,696		$	202,848	$	43,455
Lease acquisitions and other land-related costs	2,094			—		58			2,886		1,402
Pipeline, gathering facilities and other equipment, net	(703		)	—		375			3,344		(443		)
Geological, geophysical (seismic) and delay rental costs	508			—		(16		)
Geological and geophysical (seismic) costs									185		382
	$	74,162		$	—	$	4,113		$	209,263	$	44,796

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:


	Successor					Predecessor
	Nine Months			September 13		January 1
	Ended			Through		Through			Six Months Ended
	September 30,			September 30,		September 12,			June 30,			June 30,
	2017			2016		2016			2018			2017
Total capital expenditures program costs (from above)	$	74,162		$	—	$	4,113		$	209,263		$	44,796
(Increase) decrease in accrued capitalized costs	(8,140		)	—		11,301
Increase in accrued capitalized costs									(12,231		)	(2,322		)
Less:
Exploration costs charged to operations ¹:
Geological, geophysical (seismic) and delay rental costs	—			—		16
Transfers from tubular inventory and well materials	(2,581		)	—		(465		)	(4,006		)	(1,142		)
Sales and use tax refunds received and applied to property accounts									(644		)	—
Add:
Tubular inventory and well materials purchased in advance of drilling	2,657			—		211			2,677			1,100
Capitalized internal labor ¹	1,614			—		—
Capitalized internal labor									1,620			1,070
Capitalized interest	132			—		183			4,671			81
Total cash paid for capital expenditures	$	67,844		$	—	$	15,359		$	201,350		$	43,583

^{__________________________________________________________________________________}


¹	Exploration costs and certain internal labor costs were charged to operations while we applied the successful efforts method in the 2016 Predecessor period and capitalized under the full cost method in the 2017 Successor period.

Cash Flows from Financing Activities. The ~~2017~~2018 period includes borrowings of ~~$39 million and repayments of $7~~$166.5 million under the Credit Facility, a substantial portion of which were used to fund the Hunt Acquisition, while the ~~Predecessor~~2017 period ~~in 2016~~only includes borrowings of $14 million and repayments of ~~$119.1 million under the RBL. We received proceeds of $196 million from the Second Lien Facility, net of a discount, in the 2017 period.~~$2 million. We also paid ~~$1.7~~$0.8 million of debt issue costs in ~~2017~~the 2018 period in connection with amendments to the Credit Facility and ~~$7.9 million~~other costs in connection with the $200 million Second Lien Facility, or Second Lien Facility, compared to $1.1 million paid in the 2017 period in connection with an amendment to the Credit Facility. ~~Delayed receipts~~The receipt in the 2017 period of delayed proceeds attributable to the rights offering in September 2016 were fully offset by costs paid in connection with the registration of our common stock in the ~~Successor period in 2017.~~2017 period.

Capitalization

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


	September 30,			December 31,			June 30,			December 31,
	2017			2016			2018			2017
Credit Facility borrowings	$	57,000		$	25,000		$	243,500		$	77,000
Second Lien Facility term loans	188,055			—
Total debt	245,055			25,000
Second Lien Facility term loan, net							189,324			188,267
Total debt, net							432,824			265,267
Shareholders’ equity	231,762			185,548			228,612			221,639
	$	476,817		$	210,548		$	661,436		$	486,906
Debt as a % of total capitalization	51		%	12		%	65		%	54		%

Credit Facility. ~~Following the Third Amendment, the~~The Credit Facility provides for a ~~$237.5~~$340 million revolving commitment and borrowing base. The Credit Facility includes a $5$5.0 million sublimit for the issuance of letters of credit. 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 ~~generally~~ 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 ~~to pay expenses associated with our bankruptcy proceedings and~~ for general corporate purposes including working capital. The Credit Facility matures in September 2020. We had $0.8 million in letters of credit outstanding as of June 30, 2018 and December 31, 2017.

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 2.00% to 3.00%, 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 3.00% to 4.00%, 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~~June 30, ~~2017,~~2018, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was ~~4.42%~~5.58%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by ~~our parent company~~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. ~~The parent company has~~There are no ~~material independent assets~~significant restrictions on our ability or ~~operations.~~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 ~~provides for a term loan up to $200 million which we fully drew as of September 30, 2017. The Second Lien Facility matures on~~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 June 30, 2018, the actual interest rate on the Second Lien Facility was 9.10%. 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.~~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 interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Credit Facility, or EBITDAX, to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) 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 (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter ~~initially~~ of ~~4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to~~ 3.50 to 1.00.

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 for credit facilities of this nature.~~remedies. If we do not comply with the financial and other covenants in the Credit Facility and Second Lien Facility, 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~~June 30, ~~2017,~~2018, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.

Results of Operations

~~As discussed previously in the~~ ~~Overview and Executive Summary~~, the adoption of Fresh Start Accounting and the full cost method of accounting for oil and gas properties upon our emergence from bankruptcy results in the Successor not being comparable to the Predecessor for purposes of financial reporting. While the Successor effectively represents a new reporting entity for financial reporting purposes, the impact is limited to those areas associated with the basis in and accounting for our oil and gas properties (specifically depreciation, depletion and amortization, or DD&A, impairments as well as exploration expenses), general and administrative expenses due to the capitalization of certain labor costs under the full cost method, capital structure (specifically interest expense) and income taxes (due to the change in control). Accordingly, we believe that describing certain year-over-year variances and trends in our production, revenues and expenses for the three and nine months ended September 30, 2017 and 2016 without regard to the concept of a Successor and Predecessor continues to facilitate a meaningful analysis of our results of operations.

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
Successor Predecessor Successor Predecessor
Three Months September 13 July 1 Three Months September 13 July 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
(Total volume) (Volume per day)
Crude oil (MBbl & BOPD) 627
127
547
6,816
7,060
7,394
NGLs (MBbl and BOPD) 125
27
133
1,355
1,473
1,793
Natural gas (MMcf and MMcfpd) 676
174
695
7
10
9
Total (MBOE and BOEPD) 864
183
796
9,396
10,145
10,752
Combined 2017 vs. 2016 variance (MBOE and BOEPD) (115 ) (1,245 )

Three Months September 13 July 1 Three Months September 13 July 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
(MBOE) (BOE per day)
South Texas 785
164
724
8,535
9,131
9,788
Mid-Continent and other ¹
79
18
71
861
1,014
964
864
183
796
9,396
10,145
10,752

Nine Months September 13 January 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
(Total volume) (Volume per day)
Crude oil (MBbl & BOPD) 1,920
127
2,311
7,032
7,060
9,028
NGLs (MBbl and BOPD) 375
27
533
1,373
1,473
2,083
Natural gas (MMcf and MMcfpd) 2,094
174
3,012
8
10
12
Total (MBOE and BOEPD) 2,644
183
3,346
9,683
10,145
13,071
Combined 2017 vs. 2016 variance (MBOE and BOEPD) (885 ) (3,244 )

Nine Months September 13 January 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
(MBOE) (BOE per day)
South Texas 2,420
164
3,071
8,864
9,131
11,995
Mid-Continent and other ¹
224
18
276
819
1,014
1,077
2,644
183
3,346
9,683
10,145
13,071

~~_______________________~~


¹	Includes total production and average daily production of approximately 0.9 MBOE (29 BOEPD) and 10 MBOE (43 BOEPD) attributable to our former Marcellus Shale wells for each of the Predecessor periods presented. There was no production from these wells during the Successor periods.



	Total Production				Average Daily Production
	Three Months Ended		2018 vs. 2017		Three Months Ended		2018 vs. 2017
	June 30,	June 30,	Favorable		June 30,	June 30,	Favorable
	2018	2017	(Unfavorable)		2018	2017	(Unfavorable)
Crude oil (MBbl and BOPD)	1,498	685	813		16,465	7,524	8,941
NGLs (MBbl and BOPD)	269	131	138		2,960	1,440	1,520
Natural gas (MMcf and MMcfpd)	1,515	653	862		17	7	10
Total (MBOE and BOEPD)	2,020	925	1,096		22,200	10,159	12,041

	Three Months Ended		2018 vs. 2017		Three Months Ended		2018 vs. 2017
	June 30,	June 30,	Favorable		June 30,	June 30,	Favorable
	2018	2017	(Unfavorable)		2018	2017	(Unfavorable)
	(MBOE)				(BOEPD)
South Texas	1,952	864	1,088		21,451	9,498	11,953
Mid-Continent	68	60	8		749	662	88
	2,020	925	1,096		22,200	10,159	12,041

	Six Months Ended		2018 vs. 2017		Six Months Ended		2018 vs. 2017
	June 30,	June 30,	Favorable		June 30,	June 30,	Favorable
	2018	2017	(Unfavorable)		2018	2017	(Unfavorable)
Crude oil (MBbl and BOPD)	2,625	1,293	1,332		14,505	7,142	7,363
NGLs (MBbl and BOPD)	434	250	184		2,395	1,381	1,014
Natural gas (MMcf and MMcfpd)	2,486	1,418	1,068		14	8	6
Total (MBOE and BOEPD)	3,473	1,779	1,694		19,189	9,829	9,360

	Six Months Ended		2018 vs. 2017		Six Months Ended		2018 vs. 2017
	June 30,	June 30,	Favorable		June 30,	June 30,	Favorable
	2018	2017	(Unfavorable)		2018	2017	(Unfavorable)
	(MBOE)				(BOE per day)
South Texas	3,335	1,635	1,700		18,427	9,032	9,395
Mid-Continent	138	144	(6	)	762	797	(35	)
	3,473	1,779	1,694		19,189	9,829	9,360

Total production ~~decreased~~increased during the three and ~~nine~~six month periods in ~~2017~~2018 when compared to the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017 due primarily to more productive and a greater number of wells turned to sales in the ~~suspension~~2018 periods as well as incremental production from the Hunt and Devon Acquisitions. Additionally, we operated three drilling rigs during the 2018 periods as compared to two during the 2017 periods, the second of which was not contracted until mid-March 2017. These increases were partially offset by natural production declines in our former Mid-Continent wells where we have not drilled a new well since 2013, as well as certain of our ~~drilling program~~legacy Eagle Ford wells.

Approximately 74 percent and 76 percent of total production during the three and six month periods in ~~February 2016~~2018 was attributable to crude oil when compared to approximately 74 percent and 73 percent during the corresponding periods in 2017. The marginal decrease in the crude oil composition during the three month period in 2018 was attributable to certain wells that were turned to sales in the southernmost portion of our Eagle Ford acreage that have a more significant natural gas content compared to our typical Eagle Ford well profile. Our Eagle Ford production ~~declines.~~represented 97 percent and 96 percent of our total production during the three and six month periods in 2018 compared to approximately 93 percent and 92 percent from this region during the corresponding periods in 2017. During the three and six month periods in 2018, we turned 20 gross (16.9 net) and 33 gross (26.9 net) Eagle Ford wells to sales compared to seven gross (3.0 net) and 13 gross (6.6 net) wells during the corresponding periods in 2017. While we resumed ~~the~~our drilling program in November 2016, we did not turn any new wells to sales until mid-February 2017. The decline was further exacerbated by mechanical issues with our previously-contracted drilling rigs and the effects of Hurricane Harvey in August 2017 which resulted in a partial curtailment of production for several days as well as delays in our scheduled drilling and completion activities in South Texas. Approximately 73 percent of total production during each of the three and nine month periods in 2017 was attributable to oil when compared to approximately 69 percent during the each of the corresponding combined Successor and Predecessor periods in 2016. Our Eagle Ford production represented 91 percent and 92 percent of our total production during the three and nine month periods in 2017 compared to approximately 91 percent and 92 percent from this region during the corresponding combined Successor and Predecessor periods in 2016. During the three and nine month periods in 2017, we turned seven and 20 gross Eagle Ford wells to sales compared to none and five gross wells during the corresponding combined Successor and Predecessor periods in 2016.

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
Successor Predecessor Successor Predecessor
Three Months September 13 July 1 Three Months September 13 July 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
($ per unit of volume)
Crude oil $ 29,963
$ 5,508
$ 23,392
$ 47.78
$ 43.35
$ 42.75
NGLs 2,393
333
1,680
$ 19.19
$ 12.56
$ 12.66
Natural gas 1,977
475
1,889
$ 2.92
$ 2.73
$ 2.72
Total $ 34,333
$ 6,316
$ 26,961
$ 39.72
$ 34.59
$ 33.89

Combined 2017 vs. 2016 variance $ 1,056

Three Months September 13 July 1 Three Months September 13 July 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
($ per BOE)
South Texas $ 32,475
$ 5,955
$ 25,448
$ 41.36
$ 36.23
$ 35.13
Mid-Continent and other ¹
1,858
361
1,513
$ 23.45
$ 19.78
$ 21.19
$ 34,333
$ 6,316
$ 26,961
$ 39.72
$ 34.59
$ 33.89

Nine Months September 13 January 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
($ per unit of volume)
Crude oil $ 92,387
$ 5,508
$ 81,377
$ 48.12
$ 43.35
$ 35.21
NGLs 6,738
333
6,064
$ 17.98
$ 12.56
$ 11.37
Natural gas 6,200
475
6,208
$ 2.96
$ 2.73
$ 2.06
Total $ 105,325
$ 6,316
$ 93,649
$ 39.84
$ 34.59
$ 27.99

Combined 2017 vs. 2016 variance $ 5,360

Nine Months September 13 January 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
($ per BOE)
South Texas $ 100,078
$ 5,955
$ 88,849
$ 41.35
$ 36.23
$ 28.94
Mid-Continent and other ¹
5,247
361
4,800
$ 23.47
$ 19.78
$ 17.42
$ 105,325
$ 6,316
$ 93,649
$ 39.84
$ 34.59
$ 27.99

~~_______________________~~


¹	~~Includes revenues of less than $0.1 million attributable to our former Marcellus Shale wells for each of the Predecessor periods presented.~~



	Total Product Revenues							Product Revenues per Unit of Volume
	Three Months Ended				2018 vs. 2017			Three Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
								($ per unit of volume)
Crude oil	$	101,716	$	32,351	$	69,365		$	67.89	$	47.25	$	20.64
NGLs	5,533		2,043		3,490			$	20.54	$	15.59	$	4.95
Natural gas	3,912		1,880		2,032			$	2.58	$	2.88	$	(0.30	)
Total	$	111,161	$	36,274	$	74,887		$	55.02	$	39.24	$	15.78

	Three Months Ended				2018 vs. 2017			Three Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
								($ per BOE)
South Texas	$	109,544	$	34,916	$	74,628		$	56.12	$	40.40	$	15.72
Mid-Continent	1,617		1,358		259			$	23.71	$	22.55	$	1.16
	$	111,161	$	36,274	$	74,887		$	55.02	$	39.24	$	15.78

	Six Months Ended				2018 vs. 2017			Six Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
								($ per unit of volume)
Crude oil	$	172,974	$	62,424	$	110,550		$	65.89	$	48.29	$	17.60
NGLs	8,479		4,345		4,134			$	19.56	$	17.38	$	2.18
Natural gas	6,702		4,223		2,479			$	2.70	$	2.98	$	(0.28	)
Total	$	188,155	$	70,992	$	117,163		$	54.17	$	39.90	$	14.27

	Six Months Ended				2018 vs. 2017			Six Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
								($ per BOE)
South Texas	$	184,860	$	67,603	$	117,257		$	55.43	$	41.35	$	14.08
Mid-Continent	3,295		3,389		(94		)	$	23.89	$	23.49	$	0.40
	$	188,155	$	70,992	$	117,163		$	54.17	$	39.90	$	14.27

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


	Three Months Ended September 30, 2017 vs.								Nine Months Ended September 30, 2017 vs.
	Combined Predecessor and Successor Periods								Combined Predecessor and Successor Periods
	Ended September 30, 2016								Ended September 30, 2016								Three Months Ended June 30, 2018 vs. 2017							Six Months Ended June 30, 2018 vs. 2017
	Revenue Variance Due to								Revenue Variance Due to								Revenue Variance Due to							Revenue Variance Due to
	Volume			Price		Total			Volume			Price		Total			Volume		Price			Total		Volume		Price			Total
Crude oil	$	(2,016	)	$	3,079	1,063			$	(18,456	)	$	23,958	5,502			$	38,444	$	30,921		$	69,365	$	64,353	$	46,197		110,550
NGLs	(437		)	817		380			(2,114		)	2,455		341			2,155		1,335			3,490		3,189		945			4,134
Natural gas	(522		)	135		(387		)	(2,284		)	1,801		(483		)	2,483		(451		)	2,032		3,181		(702		)	2,479
	$	(2,975	)	$	4,031	$	1,056		$	(22,854	)	$	28,214	$	5,360		$	43,082	$	31,805		$	74,887	$	70,723	$	46,440		$	117,163

Our product revenues during the three and ~~nine~~six month periods in ~~2017~~2018 increased over the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017 due primarily to approximately 119 percent and 103 percent higher crude oil volumes and 44 percent and 36 percent higher crude oil prices, respectively. Our Eagle Ford crude oil production benefits from pricing based on the ~~significant increases~~LLS index which has averaged approximately six percent and eight percent higher than the comparable WTI index during the three and six month periods in ~~all product pricing~~2018, respectively. Higher natural gas revenues were primarily attributable to higher production volumes which ~~was somewhat~~were partially offset by the ~~decline~~effect of 10 percent and nine percent lower natural gas pricing during the three and six month periods, respectively. Excluding the effects of the adoption of ASC Topic 606, or $0.6 million and $1.0 million, respectively, NGL pricing actually increased by 45 percent and 26 percent during the 2018 periods as compared to the corresponding periods in ~~production described previously.~~ 2017.

Total crude oil revenues were approximately 8792 percent of our total revenues during each of the three and six month ~~period~~periods in ~~2017~~2018 as compared to 89 percent and 88 percent during the ~~combined Successor~~three and ~~Predecessor three~~six month ~~period~~periods in ~~2016.~~2017. Total Eagle Ford revenues were approximately 9599 percent and 98 percent of total revenues for ~~each of~~ the three and ~~nine~~six month periods in ~~2017~~2018 and 96 percent and 95 percent ~~and 94 percent~~ for ~~each of~~ the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016, respectively.~~2017.

Effects of Derivatives

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


	Successor				Predecessor		Successor					Predecessor
	Three Months		September 13		July 1		Nine Months			September 13		January 1
	Ended		Through		Through		Ended			Through		Through		Three Months Ended						2018 vs. 2017			Six Months Ended						2018 vs. 2017
	September 30,		September 30,		September 12,		September 30,			September 30,		September 12,		June 30,			June 30,			Favorable			June 30,			June 30,			Favorable
	2017		2016		2016		2017			2016		2016		2018			2017			(Unfavorable)			2018			2017			(Unfavorable)
Crude oil revenues, as reported	$	29,963	$	5,508	$	23,392	$	92,387		$	5,508	$	81,377	$	101,716		$	32,351		$	69,365		$	172,974		$	62,424		$	110,550
Derivative settlements, net	788		—		1,056		(1,670		)	—		48,008		(12,401		)	(466		)	(11,935		)	(19,977		)	(2,458		)	(17,519		)
	$	30,751	$	5,508	$	24,448	$	90,717		$	5,508	$	129,385	$	89,315		$	31,885		$	57,430		$	152,997		$	59,966		$	93,031

Crude oil prices per Bbl	$	47.78	$	43.35	$	42.75	$	48.12		$	43.35	$	35.21	$	67.89		$	47.25		$	20.64		$	65.89		$	48.29		$	17.60
Derivative settlements per Bbl	1.26		—		1.93		(0.87		)	—		20.77		(8.28		)	(0.68		)	(7.60		)	(7.61		)	(1.90		)	(5.71		)
	$	49.04	$	43.35	$	44.68	$	47.25		$	43.35	$	55.98	$	59.61		$	46.57		$	13.04		$	58.28		$	46.39		$	11.89

Gain (Loss) on ~~the~~ 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 ~~for~~forth the total gains and ~~losses~~(losses) recognized for the periods presented:



	Three Months Ended					2018 vs. 2017		Six Months Ended					2018 vs. 2017
	June 30,		June 30,			Favorable		June 30,		June 30,			Favorable
	2018		2017			(Unfavorable)		2018		2017			(Unfavorable)
Gain (loss) on sales of assets, net	$	4	$	(134	)	$	138	$	79	$	(69	)	$	148

There were insignificant net gains and losses recognized during each of the three and ~~nine~~six month periods in 2018 and 2017 attributable to the disposition of certain support equipment, ~~and~~ tubular inventory and well materials. The corresponding combined Successor and Predecessor periods in 2016 reflect the amortization of deferred gains from our 2014 transactions associated with the sale of crude oil and natural gas gathering assets in South Texas. The unamortized portions of those deferred gains were ultimately reversed from our Condensed Consolidated Balance Sheet in connection with our application of Fresh Start Accounting in September 2016.

Other Revenues, net

Other revenues, net, includes fees for marketing, water disposal, gathering, transportation and compression that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our operations. ~~During the Predecessor periods, these revenues also included fees for water supply services as well as charges for accretion attributable to our unused firm transportation obligation.~~

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



	Three Months Ended				2018 vs. 2017		Six Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable		June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)		2018		2017		(Unfavorable)
Other revenues, net	$	415	$	142	$	273	$	557	$	345	$	212

Other revenues, net increased during the three and ~~nine~~six month periods in ~~2017~~2018 from the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017 due primarily to higher ~~marketing~~ fees ~~partially offset by lower water disposal~~as described above charged to third parties due to substantially higher production upon which such fees resulting from lower overall production. The combined Successor and Predecessor nine month period in 2016 included charges for reserves of certain of our receivables from joint venture partners and charges attributable to the accretion of unused firm transportation, both of which are ~~presented as contra-revenue items in this caption. There were no firm transportation charges in the 2017 periods because the underlying obligation was rejected in our bankruptcy proceedings.~~based.

Lease Operating ~~Expense~~Expenses

~~Lease operating expense, or~~ 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				2018 vs. 2017			Six Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
Lease operating	$	8,730	$	5,370	$	(3,360	)	$	16,026	$	10,286	$	(5,740	)
Per unit of production ($ per BOE)	$	4.32	$	5.81	$	1.49		$	4.61	$	5.78	$	1.17
% change per unit of production					25.6		%					20.2		%

LOE increased on an absolute basis, but declined on a per unit basis during the three and ~~nine~~six month periods in ~~2017~~2018 when compared to the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017. The absolute increases were due primarily to ~~certain costs associated with maintaining our portfolio of operating wells, which are less variable in nature and are therefore adversely affected by lower~~higher production volume ~~as well as higher surface and other repair and maintenance costs. We proceeded with certain of these repair and maintenance efforts during~~including the ~~third quarter of 2017 in order to recover a portion~~incremental effects of the Devon and Hunt Acquisitions. The higher production ~~shortfall brought about by Hurricane Harvey and operational delays discussed above. While we incurred~~volume also had the effect of decreasing the overall per unit cost, particularly those costs that have a higher ~~such repair~~fixed cost component. Furthermore, comprehensive maintenance costs in the ~~three~~second half of 2017 improved production and ~~nine month periods in 2017, they were partially offset by continuing~~ cost ~~containment efforts that we implemented throughout 2016 and~~efficiency progressing into ~~2017 as well as~~ the ~~effects of lower industry-wide pricing for certain oilfield products and services.~~2018 periods.

Gathering, Processing and Transportation

~~Gathering, processing and transportation, or~~ 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				2018 vs. 2017			Six Months Ended				2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
Gathering, processing and transportation	$	4,574	$	2,555	$	(2,019	)	$	7,933	$	5,106	$	(2,827	)
Per unit of production ($ per BOE)	$	2.26	$	2.76	$	0.50		$	2.28	$	2.87	$	0.59
% change per unit of production					18.1		%					20.6		%

GPT ~~decreased~~expense increased on an absolute basis during the three and ~~nine~~six month periods in ~~2017~~2018 when compared to the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017 due primarily to substantially ~~lower~~higher production volumes as discussed above ~~and~~partially offset by the effect of ~~an amendment to our gathering agreement with Republic Midstream, LLC that became effective in August~~the adoption of ~~2016.~~ASC Topic 606, or $0.6 million and $1.0 million, respectively. Per unit rates were favorably impacted by the aforementioned contractual amendment. Prior to that time we had incurred charges for production falling below our minimum commitments which were previously higher. We also incurred costs declined in the ~~combined Successor~~2018 periods due primarily to the effect of the adoption of ASC Topic 606, or $0.28 and Predecessor nine month period in 2016 for unused firm transportation services in the Marcellus Shale prior to our termination of operations in that region. There were no such costs incurred in the periods in 2017$0.29 per BOE, as well as the ~~underlying contracts were rejected in~~effect of additional production at the wellhead with no corresponding GPT expense subsequent to the achievement of required minimum crude oil volumes transported by pipeline within our ~~bankruptcy proceedings.~~

Eagle Ford operating region.

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 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:


	Successor						Predecessor			Successor						Predecessor
	Three Months			September 13			July 1			Nine Months			September 13			January 1
	Ended			Through			Through			Ended			Through			Through			Three Months Ended						2018 vs. 2017			Six Months Ended						2018 vs. 2017
	September 30,			September 30,			September 12,			September 30,			September 30,			September 12,			June 30,			June 30,			Favorable			June 30,			June 30,			Favorable
	2017			2016			2016			2017			2016			2016			2018			2017			(Unfavorable)			2018			2017			(Unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	1,643		$	288		$	1,315		$	4,996		$	288		$	2,695		$	5,291		$	1,698		$	(3,593	)	$	8,900		$	3,353		$	(5,547	)
Ad valorem taxes	25			87			(741		)	770			87			795			504			421			(83		)	987			745			(242		)
	$	1,668		$	375		$	574		$	5,766		$	375		$	3,490		$	5,795		$	2,119		$	(3,676	)	$	9,887		$	4,098		$	(5,789	)
Per unit production ($/BOE)	$	1.93		$	2.05		$	0.72		$	2.18		$	2.05		$	1.04
Per unit production ($ per BOE)																			$	2.87		$	2.29		$	(0.58	)	$	2.85		$	2.30		$	(0.55	)
Production/severance tax rate as a percent of product revenue	4.8		%	4.6		%	4.9		%	4.7		%	4.6		%	2.9		%	4.8		%	4.7		%				4.7		%	4.7		%

Production taxes increased on both an absolute and per unit basis during the three and ~~nine~~six month periods in ~~2017~~2018 when compared to the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016~~2017 due primarily to ~~the recognition of certain severance tax refunds from Oklahoma in the 2016 periods that were attributable to prior years, as well as~~increased production volume and higher commodity sales ~~prices despite a decline in production volume in the Successor periods in 2017. In the latter half of 2016 and into 2017, we adjusted our accruals~~prices. Accruals for ad valorem taxes ~~downward, primarily in South Texas, reflecting lower oil~~have also increased for the 2018 periods as we have grown our assessable property base and ~~gas property valuations.~~we anticipate higher assessments as a result of higher commodity prices and increased working interests.

General and Administrative

Our ~~general and administrative~~G&A expenses ~~or G&A,~~ 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:

Successor Predecessor Successor Predecessor
Three Months September 13 July 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
Primary G&A $ 4,230
$ 1,458
$ 4,026
$ 10,404
$ 1,458
$ 15,596
Share-based compensation
Liability-classified —
—
—
—
—
(19 )
Equity-classified ¹
1,013
—
147
2,707
—
1,511
Significant special charges:
Acquisition transaction costs 1,505
—
—
1,505
—
—
ERP system upgrade costs 204
—
—
204
—
—
Strategic and financial advisory costs —
—
—
—
—
18,036
Restructuring expenses —
18
2,722
(20 ) 18
3,821
Total G&A $ 6,952
$ 1,476
$ 6,895
$ 14,800
$ 1,476
$ 38,945
Per unit of production
($/BOE)
$ 8.04
$ 8.07
$ 8.67
$ 5.60
$ 8.07
$ 11.64
Per unit of production excluding all share-based compensation and other significant special charges identified above ($/BOE) $ 4.89
$ 7.97
$ 5.06
$ 3.93
$ 7.97
$ 4.66

~~_______________________~~


¹	~~As described in Notes 2 and 15 to the Condensed Consolidated Financial Statements, the amounts for the Predecessor period from July 1 through September 12, 2016 periods has been recasted.~~



	Three Months Ended				2018 vs. 2017			Six Months Ended					2018 vs. 2017
	June 30,		June 30,		Favorable			June 30,		June 30,			Favorable
	2018		2017		(Unfavorable)			2018		2017			(Unfavorable)
Primary G&A	$	4,391	$	2,854	$	(1,537	)	$	8,605	$	6,135		$	(2,470	)
Share-based compensation (equity-classified)	875		848		(27		)	2,451		1,694			(757		)
Significant special charges:
Acquisition and divestiture transaction costs	56		—		(56		)	487		—			(487		)
Executive retirement costs	—		—		—			250		—			(250		)
Restructuring expenses	—		—		—			—		(20		)	(20		)
Total G&A	$	5,322	$	3,702	$	(1,620	)	$	11,793	$	7,809		$	(3,984	)
Per unit of production ($ per BOE)	$	2.63	$	4.00	$	1.37		$	3.40	$	4.39		$	0.99
Per unit of production excluding share-based compensation and other significant special charges identified above ($ per BOE)	$	2.17	$	3.09	$	0.92		$	2.48	$	3.45		$	0.97

Our primary G&A expenses ~~decreased~~increased on an absolute and decreased on a per unit basis during the three and ~~nine~~six month periods in ~~2017~~2018 compared to the corresponding ~~combined Successor and Predecessor~~ periods in ~~2016.~~2017. The ~~decrease~~absolute increase is due primarily to the effects ~~of: (i) lower~~of higher payroll, benefits and ~~benefits~~support costs attributable to a ~~lower~~higher overall employee ~~headcount, partially offset by costs associated with recent hires consistent with our current growth plans (ii)~~headcount. Higher production volume had the ~~capitalization~~effect of ~~certain labor and benefits costs to oil and gas properties in accordance with the full cost method in the 2017 periods (iii) the relocation~~reducing G&A per unit of our headquarters from Radnor, Pennsylvania to Houston, Texas and related move to a smaller office location, (iv) reduced travel and entertainment and (v) lower corporate support costs consistent with our efforts throughout 2016 and 2017 to rationalize our support cost base.

Liability-classified share-based compensation in the 2016 Predecessor period was attributable to our former performance-based restricted stock units, or PBRSUs, and represents mark-to-market adjustments associated with the change in fair value of the then outstanding PBRSU grants. Our common stock performance relative to a defined peer group was less favorableproduction during the ~~2016 periods resulting in a mark-to-market reversal. All of the unvested PBRSUs were canceled upon our emergence from bankruptcy.~~2018 three and six month periods.

Equity-classified share-based compensation charges during the ~~period in 2017~~periods presented are attributable to the amortization of compensation cost associated with the grants of time-vested restricted stock units, or RSUs, ~~in the fourth quarter of 2016~~ and ~~each of the three quarters of 2017 as well as~~ performance restricted stock units, or ~~PRSUs, in the first and third quarters of 2017.~~PRSUs. The ~~2017~~ grants of RSUs and PRSUs are described in greater detail in Note 15 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 ~~2016 periods include~~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 six month period in 2018 includes a charge ~~for~~of $0.6 million attributable to the ~~cancellation~~accelerated vesting of ~~all of~~certain RSUs and PRSUs in connection with the ~~RSUs outstanding prior to our bankruptcy filing in May 2016, partially offset by forfeitures of the Predecessor’s stock options. All~~retirement of our ~~equity-classified share-based compensation represents non-cash expenses.~~Executive Chairman in February 2018.

During the ~~third~~second quarter of ~~2017,~~2018, we incurred transaction costs associated with our Mid-Continent divestiture. In addition to these costs, the six month period of 2018 is comprised primarily of transaction costs associated with the Hunt Acquisition, including ~~advisory,~~ legal, due diligence and other professional ~~fees as well as~~fees. We also paid certain costs ~~associated with an upgrade~~attributable to ~~our ERP system. During~~ the ~~Predecessor period in 2016, we incurred substantial professional fees and other consulting costs associated with our consideration of strategic financing alternatives and related activities in advance~~retirement of our ~~bankruptcy filing. In connection with our efforts to simplify and reduce our administrative cost structure, we terminated a total of 45 employees during the combined Successor and Predecessor periods~~former Executive Chairman in ~~2016 and incurred related termination and severance benefit costs during the Predecessor periods.~~

~~Exploration~~

While applying the successful efforts method of accounting to our oil and gas properties during the Predecessor periods in 2016, we incurred costs which were charged to operations in accordance with the successful efforts method. In the Successor periods, we applied the full cost method of accounting whereby these costs are capitalized. See the discussion of our capital expenditures program included in “Financial Condition - ~~Cash Flows” above and~~February 2018 (see Note 710 to the Condensed Consolidated Financial ~~Statements for a discussion of certain capitalized costs.~~Statements). The ~~following table sets forth the components of exploration expense for the Predecessor periods presented:~~

~~In addition~~six month period in 2017 includes adjustments to ~~normal exploration costs associated with the successful efforts method in the Predecessor periods in 2016, primarily unproved leasehold amortization, we incurred: (i) early termination charges~~severance-related restructuring accruals that were originally established in connection with ~~the release of a drilling rig~~our reorganization in the Eagle Ford, (ii) charges for the failure to complete a drilling carry commitment attributable to certain acreage acquired in the Eagle Ford, (iii) a charge for coiled tubing services that were not utilized by the contract expiration date and (iv) the write-off of certain uncompleted well costs prior to the aforementioned change in accounting method to the full cost method.

2016.

Depreciation, Depletion and Amortization

As discussed with respect to exploration expenses above, our adoption of the full cost method in place of the successful efforts method of accounting for oil and gas properties also impacted the determination of our DD&A during the Successor periods in 2017 and 2016 as compared to the Predecessor periods in 2016. The following table sets forth total and per unit costs for DD~~&A:~~&A for the periods presented:


	Successor				Predecessor		Successor				Predecessor
	Three Months		September 13		July 1		Nine Months		September 13		January 1
	Ended		Through		Through		Ended		Through		Through		Three Months Ended				2018 vs. 2017			Six Months Ended				2018 vs. 2017
	September 30,		September 30,		September 12,		September 30,		September 30,		September 12,		June 30,		June 30,		Favorable			June 30,		June 30,		Favorable
	2017		2016		2016		2017		2016		2016		2018		2017		(Unfavorable)			2018		2017		(Unfavorable)
DD&A expense	$	10,659	$	2,029	$	8,024	$	31,545	$	2,029	$	33,582	$	31,273	$	11,076	$	(20,197	)	$	53,354	$	20,886	$	(32,468	)
DD&A Rate ($/BOE)	$	12.32	$	11.09	$	10.09	$	11.93	$	11.09	$	10.04
DD&A Rate ($ per BOE)													$	15.48	$	11.97	$	(3.51	)	$	15.36	$	11.74	$	(3.62	)

~~The effects of higher depletion rates resulted in higher~~ DD&A increased on an absolute and per unit basis during the three ~~months~~and six month periods ended ~~September 30, 2017~~in 2018 when compared to the corresponding ~~combined Successor~~periods in 2017. Higher production volume provided for an increase of approximately $13.1 million and ~~Predecessor period in 2016. Lower production volumes net of the effects of higher depletion rates were the primary factors~~$19.9 million while $7.1 million and $12.6 million was attributable to the decline in DD&A during the nine months ended September 30, 2017 when compared to the corresponding combined Successor and Predecessor period in 2016. The Successor periods include a higher proportion of capitalized costs relative to the underlying proved reserves, consistent with the full cost method, when compared to the Predecessor periods which utilized the successful efforts method which, in part, gives rise to the higher DD&A rates in the ~~Successor~~2018 periods. The higher DD&A rates in the 2018 periods ~~when compared~~were attributable to costs added to the ~~Predecessor periods.~~full cost pool, including those from the Devon and Hunt Acquisitions, during a period of rising crude oil prices while the DD&A rate for the 2017 period is based primarily on the fair value of our properties at the time of our emergence from bankruptcy in September 2016.

Interest Expense

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


	Successor					Predecessor		Successor					Predecessor
	Three Months			September 13		July 1		Nine Months			September 13		January 1
	Ended			Through		Through		Ended			Through		Through			Three Months Ended						2018 vs. 2017			Six Months Ended						2018 vs. 2017
	September 30,			September 30,		September 12,		September 30,			September 30,		September 12,			June 30,			June 30,			Favorable			June 30,			June 30,			Favorable
	2017			2016		2016		2017			2016		2016			2018			2017			(Unfavorable)			2018			2017			(Unfavorable)
Interest on borrowings and related fees	$	880		$	180	$	1,363	$	1,785		$	180	$	36,013		$	7,730		$	515		$	(7,215	)	$	13,778		$	905		$	(12,873	)
Accretion of original issue discount																168			—			(168		)	333			—			(333		)
Amortization of debt issuance costs	374			38		—		1,362			38		22,188			680			800			120			1,311			988			(323		)
Capitalized interest	(52		)	—		—		(133		)	—		(183		)	(2,428		)	(41		)	2,387			(4,671		)	(81		)	4,590
	$	1,202		$	218	$	1,363	$	3,014		$	218	$	58,018		$	6,150		$	1,274		$	(4,876	)	$	10,751		$	1,812		$	(8,939	)

Interest expense increased during the three and ~~nine~~six month periods in 2018 as compared to the corresponding periods in 2017 isdue primarily ~~attributable~~ to higher outstanding balances under the Credit Facility, ~~along with two days of~~including amounts borrowed to fund our larger capital expenditure program in 2018 and the Hunt Acquisition, as well as interest attributable to the Second Lien ~~Facility. Interest expense during~~Facility that was issued in September 2017 in order to fund the ~~corresponding combined Successor~~Devon Acquisition. Furthermore, the Credit Facility and ~~Predecessor~~the Second Lien Facility are variable-rate instruments and both have been subject to periodic increases in LIBOR rates on a consistent basis since the comparable periods in ~~2016~~2017. The accretion of original issue discount is entirely attributable to the ~~RBL~~Second Lien Facility and ~~our former 7.25% Senior Notes due 2019 and 8.50% Senior Notes due 2020, or~~ the ~~Senior Notes. Interest on the Senior Notes was charged through the date of our bankruptcy filing in May 2016 upon which time the accrual of interest was suspended. Amortization~~amortization of debt issuance costs inincludes amounts attributable to both the ~~three~~Credit Facility and ~~nine month~~Second Lien Facility. We capitalized a larger portion of interest during each of the 2018 periods as we maintained a substantially larger portion of unproved property as compared to the corresponding periods in 2017 ~~included write-offs of $0.2 million and $0.8 million attributable~~due primarily to ~~previously capitalized debt issue costs due to changes~~the Devon Acquisition in ~~the composition of financial institutions comprising the Credit Facility bank group while the Predecessor period ended~~ September 12, 2016 included a $20.5 million accelerated write-off of issue costs associated with the RBL and Senior Notes in advance of our bankruptcy filing. Notwithstanding these write-offs, the overall decrease is due to substantially higher outstanding indebtedness during the 2016 periods.2016.

Derivatives

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

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, by commodity type, for the periods presented:



	Three Months Ended					2018 vs. 2017			Six Months Ended					2018 vs. 2017
	June 30,			June 30,		Favorable			June 30,			June 30,		Favorable
	2018			2017		(Unfavorable)			2018			2017		(Unfavorable)
Crude oil derivative gains (losses)	$	(52,241	)	$	11,061	$	(63,302	)	$	(71,036	)	$	28,077	$	(99,113	)

In the three and six month periods in 2018, the forward curve for commodity prices was increasing relative to our weighted-average hedged prices while the forward curve for such prices declined relative to our weighted-average hedged prices in the comparable 2017 periods. We ~~received cash settlements of $0.8 million and~~ paid cash settlements of ~~$1.7~~

$12.4 million and $20.0 million and $0.5 million and $2.5 million in the three and ~~nine-month~~six month periods in 2018 and 2017, ~~as compared to the receipt~~respectively.

Other, net

Other, net includes interest income, non-service costs associated with our retiree benefit plans and miscellaneous items of ~~$1.1 million~~income and ~~$48.0 million of cash settlements from crude oil derivatives during the corresponding combined Successor~~expense that are not directly associated with our current operations, including certain recoveries and ~~Predecessor periods in 2016. The changes in total cash settlements are~~write-offs attributable to ~~the net payment of cash settlements from derivatives during the periods in 2017 compared to the net receipt of settlements during the corresponding combined Successor~~prior years and ~~Predecessor periods in 2016. Specifically, our hedged prices for maturing contracts~~properties that have exceeded the WTI, crude oil prices on our post-petition derivatives resulting in net payments in the periods in 2017 while the opposite situation occurred in the corresponding combined Successor and Predecessor periods in 2016 resulting in receipt of cash settlements as well as the early termination of certain pre-petition derivative contracts in the Predecessor periods in 2016 which accelerated the receipt of cash settlements.

~~Other, net~~been divested.

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



	Three Months Ended					2018 vs. 2017			Six Months Ended					2018 vs. 2017
	June 30,			June 30,		Favorable			June 30,			June 30,		Favorable
	2018			2017		(Unfavorable)			2018			2017		(Unfavorable)
Other, net	$	(16	)	$	82	$	(98	)	$	(74	)	$	62	$	(136	)

InOther, net expense increased during the three and six month periods in 2018 as compared to the corresponding periods in 2017 ~~we recorded~~due primarily to interest charges applicable to a settlement with a royalty owner. Each of the three and six month periods includes comparable charges associated with our retiree benefit plans, and the 2018 period is partially offset by interest income ~~and we recovered certain costs~~earned on the escrow account attributable to ~~assets that were sold~~the Devon Acquisition prior to the escrow account’s liquidation in prior years. In the corresponding combined Successor and Predecessor periods in 2016 we wrote-off unrecoverable amounts from prior years, including GPT charges and other revenue deductions, attributable primarily to properties that had been sold.March 2018.

~~Reorganization Items, net~~

Income Taxes

The following table summarizes ~~the components included in Reorganization items, net~~our income tax expense for the periods presented:

Successor Predecessor Successor Predecessor
Three Months September 13 July 1 Nine Months September 13 January 1
Ended Through Through Ended Through Through
September 30, September 30, September 12, September 30, September 30, September 12,
2017 2016 2016 2017 2016 2016
Gains on settlement of liabilities subject to compromise $ —
$ —
$ 1,150,248
$ —
$ —
$ 1,150,248
Fresh Start Accounting adjustments —
—
28,319
—
—
28,319
Legal and professional fees and expenses —
—
(22,739 ) —
—
(29,976 )
Settlements attributable to contract amendments —
—
(2,550 ) —
—
(2,550 )
Debtor-in-Possession credit facility costs and commitment fees —
—
(27 ) —
—
(170 )
Write-off of prepaid directors and officers insurance —
—
(832 ) —
—
(832 )
Other reorganization items —
—
(46 ) —
—
(46 )
$ —
$ —
$ 1,152,373
$ —
$ —
$ 1,144,993



	Three Months Ended						2018 vs. 2017		Six Months Ended						2018 vs. 2017
	June 30,			June 30,			Favorable		June 30,			June 30,			Favorable
	2018			2017			(Unfavorable)		2018			2017			(Unfavorable)
Income tax expense	$	—		$	—		$	—	$	(163	)	$	—		$	(163	)
Effective tax rate	—		%	—		%			2.1		%	—		%

~~Reorganization items,~~On December 22, 2017, the U.S. Congress enacted comprehensive tax legislation as part of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act, or the TCJA. The TCJA makes broad and complex changes to the U.S. tax code. The most significant aspects of the TCJA applicable to us include but are not limited to: (i) reducing the U.S. federal corporate income tax rate from 35% to 21%; (ii) allowing the immediate deduction of certain new investments in lieu of depreciation expense over time; (iii) creating a new limitation on deductible interest expense; (iv) changing rules related to use and limitations of net ~~includes costs incurred~~operating loss, or NOL, carryforwards created in tax years beginning after December 31, 2017 and (v) repeal of the corporate alternative minimum tax, or AMT.

In connection with our initial analysis of the impact of the TCJA, our Condensed Consolidated Balance Sheet as of December 31, 2017 included a deferred tax asset of $4.9 million attributable to our AMT credit carryforwards that were previously fully reserved, but became realizable in connection with the ~~Predecessor’s bankruptcy proceedings including professional fees for attorneys, financial consultants, claims processors~~AMT provisions of the TCJA. We continue to analyze the impacts of the TCJA on the Company and others as well as fees associated with establishing the Predecessor’s debtor-in-possession credit facility as well as commitment fees for the period from the date the facility was established in May 2016 through September 12, 2016.

~~Income Taxes~~

~~The following table sets forth the income tax benefit (expense) recognized for the periods presented:~~

refine our estimates during 2018.

We recognized a federal and state income tax expense for the three and ~~nine month~~six-month periods in ~~2017~~2018 at ~~the~~a blended rate of ~~35.52%~~21.6%; however, the federal and state tax ~~expense was fully~~expenses were offset by ~~an adjustment~~adjustments to the valuation allowance against our net deferred tax ~~assets.~~assets along with an adjustment of $0.2 million for the six month period to the deferred tax asset related to sequestration of a portion of the aforementioned AMT credit carryforward resulting in an effective tax rate of 2.1%. The effect of the adjustment was to reduce our deferred tax asset to $4.8 million as of June 30, 2018. We recognized a federal income tax ~~benefit~~benefits for the ~~corresponding combined Successor~~three and ~~Predecessor periods in 2016~~six months ended June 30, 2017 at the ~~statutory~~blended rate of ~~35%~~35.2% which was fully offset by a valuation allowance against our net deferred tax assets. 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, primarily as a result of ~~our~~ cumulative losses. ~~We received a state income tax refund of less than $0.1 million during the combined Successor and Predecessor periods ended September 30, 2016.~~

We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses, or NOLs. We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control that occurred upon our emergence from bankruptcy. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets.

Off Balance Sheet Arrangements

As of ~~September~~June 30, ~~2017,~~2018, we had no off-balance sheet arrangements other than lease arrangements, information technology licensing, service agreements, employment 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, ~~2016.~~

As described in Note 2 to our Condensed Consolidated Financial Statements, we applied Fresh Start Accounting to our Condensed Consolidated Financial Statements and we also adopted the full cost method of accounting for our oil and gas properties upon our emergence from bankruptcy in September 2016.

2017.

Disclosure of the Impact of Recently Issued Accounting ~~Standards to be Adopted in the Future~~Pronouncements Pending Adoption

In ~~March 2017,~~June 2016, the Financial Accounting Standards Board, or ~~FASB, issued Accounting Standards Update, or ASU, 2017–07,~~ ~~Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost~~, or ASU 2017–07, which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of “General and administrative” expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. We will adopt ASU 2017–07 in January 2018.

~~In June 2016, the~~ 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 and the period for which we will adopt the standard, as well as monitoring developments regarding ASU 2016–13 that are unique to our industry.

In February 2016, the FASB issued ASU 2016–02, Leases, or ASU 2016–02, which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Together with recent related amendments to GAAP, ASU 2016–02 represents ASC Topic 842 Leases, or “ASC Topic 842, which supersedes all current GAAP with respect to leases. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ~~ASU 2016–02~~ASC Topic 842 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ~~ASU 2016–02~~ASC Topic 842 is January 1, 2019, with early adoption permitted. ~~We believe that ASU 2016–02~~

ASC Topic 842 will ~~likely~~ be applicable to ~~our oil and natural gas gathering commitment arrangements as described in Note 13 to the Condensed Consolidated Financial Statements,~~ our existing leases for office facilities and certain office equipment, vehicles and certain field equipment, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of ~~twelve~~12 months to the extent we may have such contracts in the future. In addition, we believe that our crude oil and natural gas gathering commitment arrangements, as described in Note 13, include provisions that could be construed as leases. Our crude oil and natural gas gathering arrangements are fairly complex and ~~involve~~include, among other provisions, multiple elements and term lengths, certain volumetric-based minimums and varying degrees of optionality available to both us and the service providers. Furthermore, these arrangements have certain material payment terms that are variable in nature which, depending upon the outcome of our analysis and resulting conclusions, could ~~be construed~~have a significant impact on the amounts recognized as ~~leases.~~right of use assets and corresponding lease liabilities. We anticipate that the adoption of ASC Topic 842 may significantly increase our total assets and liabilities. Accordingly, we are continuing to evaluate the effect that ~~ASU 2016–02~~ASC Topic 842 will have on our Consolidated Financial Statements and related ~~disclosures as well as~~disclosures. We plan adopt ASC Topic 842 on the ~~period for which we~~effective date in 2019 using the optional transition method and will ~~adopt~~recognize a cumulative-effect adjustment to the ~~standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019.~~opening balance of retained earnings. We are also continuing to monitor developments regarding ~~ASU 2016–02~~ASC Topic 842 that are unique to our industry.

~~In May 2014, the FASB issued ASU 2014–09,~~ ~~Revenues from Contracts with Customers~~, or ASU 2014–09, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, the terms of the individual commodity purchase, joint operating agreements and other contracts underlying these types of transactions will determine the appropriate recognition, measurement and disclosure once ASU 2014–09 has been adopted. Also, to the extent applicable, we are considering our participation in certain of these transactions as either a principal or agent. In addition, the recognition, measurement and disclosure of producer imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water disposal revenues, while not significant, could be impacted to some degree. Our non-product revenues are projected to represent less than $1 million of our total revenues on an annualized basis; however, that level could rise in future periods based on the potential expansion and growth of our operations. In summary, with the exception of more expansive disclosures, we have not identified any potentially material impact attributable to ASU 2014–09. While we are continuing to evaluate the overall effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, our remaining efforts are primarily focused on developing controls and procedures to facilitate the ongoing process of analysis of future contracts and their terms in order to support the appropriate accounting and disclosure. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk.

~~Not required~~Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.

Interest Rate Risk

All of our long-term debt instruments are subject to variable interest rates. As of June 30, 2018, we had borrowings of $243.5 million and $200 million under the Credit Facility and Second Lien Facility at interest rates of 5.58% and 9.10%, 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 interest payments of approximately $4 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 ~~smaller reporting companies.~~these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as swaps) to seek to mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe to be of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of crude oil. We have not typically entered into derivative instruments with respect to NGLs, although we may do so in the future.

As of June 30, 2018, our commodity derivative portfolio was in a net liabilities 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 six months ended June 30, 2018, we reported net commodity derivative loss of $71.0 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 6 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

The following table sets forth our commodity derivative positions as of June 30, 2018:



		Average	Weighted
		Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Third quarter 2018	Swaps-WTI	10,455	$	57.05	$	—	$	14,270
Third quarter 2018	Swaps-LLS	6,000	$	65.27	—		5,605
Fourth quarter 2018	Swaps-WTI	10,455	$	57.05	—		11,332
Fourth quarter 2018	Swaps-LLS	6,000	$	65.27	—		4,418
First quarter 2019	Swaps-WTI	6,446	$	54.46	—		6,999
First quarter 2019	Swaps-LLS	5,000	$	59.17	—		5,310
Second quarter 2019	Swaps-WTI	6,421	$	54.48	—		6,115
Second quarter 2019	Swaps-LLS	5,000	$	59.17	—		4,568
Third quarter 2019	Swaps-WTI	6,397	$	54.50	—		5,337
Third quarter 2019	Swaps-LLS	5,000	$	59.17	—		3,876
Fourth quarter 2019	Swaps-WTI	6,398	$	54.50	—		4,635
Fourth quarter 2019	Swaps-LLS	5,000	$	59.17	—		3,221
First quarter 2020	Swaps-WTI	6,000	$	54.09	—		3,846
Second quarter 2020	Swaps-WTI	6,000	$	54.09	—		3,302
Third quarter 2020	Swaps-WTI	6,000	$	54.09	—		2,844
Fourth quarter 2020	Swaps-WTI	6,000	$	54.09	—		2,451
Settlements to be paid in subsequent period							4,607

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, natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.



	Change of $10.00 per Bbl of Crude Oil or $1.00 per MMBtu of Natural Gas ($ in millions)
	Increase			Decrease
Effect on the fair value of crude oil derivatives ¹	$	(97.0	)	$	85.8

Effect of crude oil price changes for the remainder of 2018 on operating income, excluding derivatives ²	$	19.3		$	(19.3	)
Effect of natural gas price changes for the remainder of 2018 on operating income ²	$	2.8		$	(2.8	)

_____________________________


¹	Based on derivatives outstanding as of June 30, 2018.


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~~June 30, ~~2017~~2018. 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~~June 30, ~~2017~~2018, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended ~~September~~June 30, ~~2017,~~2018, no changes were made in 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.

On May 12, 2016, we and eight of our subsidiaries filed voluntary petitions (In re Penn Virginia Corporation, et al. Case No. 16-32395) seeking relief under the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of ~~Virginia.~~Virginia, or the Bankruptcy Court.

On August 11, 2016, the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates and we subsequently emerged from bankruptcy on September 12, 2016. See Note 4 to our Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements,” for a more detailed discussion of our bankruptcy proceedings.

On February 7, 2017, a former shareholder of the Company filed a Complaint in the Bankruptcy Court requesting that the Bankruptcy Court set aside its prior order confirming the Plan, previously confirmed on August 11, 2016. We filed a motion to dismiss the proceeding which was granted by the Bankruptcy Court on July 21, 2017. The former shareholder filed a notice of appeal to the U.S. District Court for the Eastern District of Virginia on July 27, 2017. As reflected by the Bankruptcy Court’s ruling, we believe this matter is without merit and will defend confirmation of the Plan. Absent a reversal of the Bankruptcy Court’s decision, this matter has no impact on the order confirming the Plan.

~~See Note 13 to our Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements.”~~ We are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Note 13 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, ~~2016.~~2017.


Item 6.	Exhibits.



(~~10.1~~)	Master Assignment, Agreement and Amendment No. 3 to Credit Agreement, dated as of September 29, 2017, among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).

(~~10.2~~)	Credit Agreement, dated as of September 29, 2017, by and among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, the lenders party thereto and Jefferies Finance LLC, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).

(~~10.3~~)	Pledge and Security Agreement, dated as of September 29, 2017, by Penn Virginia Holding Corp., Penn Virginia Corporation and the other grantors party thereto in favor of Jefferies Finance LLC, as administrative agent and collateral agent for the benefit of the secured parties thereunder (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).

(~~10.4~~)	Intercreditor Agreement, dated as of September 29, 2017, by and among Penn Virginia Holding Corp., Penn Virginia Corporation, the subsidiaries of Penn Virginia Holding Corp. party thereto, Wells Fargo, National Association and Jefferies Finance LLC (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on October 5, 2017).

(~~10.5~~)*	~~Purchase and Sale Agreement by and between Devon Energy Production Company, L.P. as Seller, and Penn Virginia Oil & Gas, L.P. as Buyer dated as of July 29, 2017.~~

(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) *	XBRL Instance Document

(101.SCH) *	XBRL Taxonomy Extension Schema Document

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

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

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

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

_____________________________


*	Filed herewith.


†	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, ~~as amended,~~ the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	PENN VIRGINIA CORPORATION
	~~(Registrant)~~

August 8, 2018	By:	/s/ STEVEN A. HARTMAN	~~November 9, 2017~~
		Steven A. Hartman
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

August 8, 2018	By:	/s/ TAMMY L. HINKLE	~~November 9, 2017~~
		Tammy L. Hinkle
		Vice President and Controller
		(Principal Accounting Officer)

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