Document

10-Q 1 pva-2017930x10q.htm 10-Q Document

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 30, 2017



¨	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 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	o
Non-accelerated filer	o	(Do not check if a smaller reporting company)	Smaller reporting company	ý
			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 3, 2017, 15,004,270 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended September 30, 2017

Table of Contents



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

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
	September 30, 2017			September 30, 2016			September 12, 2016
Revenues
Crude oil	$	92,387		$	5,508		$	81,377
Natural gas liquids	6,738			333			6,064
Natural gas	6,200			475			6,208
(Loss) gain on sales of assets, net	(60		)	—			1,261
Other, net	462			33			(600		)
Total revenues	105,727			6,349			94,310
Operating expenses
Lease operating	15,540			756			15,626
Gathering, processing and transportation	7,505			576			13,235
Production and ad valorem taxes	5,766			375			3,490
General and administrative	14,800			1,476			38,945
Exploration	—			—			10,288
Depreciation, depletion and amortization	31,545			2,029			33,582
Total operating expenses	75,156			5,212			115,166
Operating income (loss)	30,571			1,137			(20,856		)
Other income (expense)
Interest expense	(3,014		)	(218		)	(58,018		)
Derivatives	15,802			(4,369		)	(8,333		)
Other, net	104			9			(3,184		)
Reorganization items, net	—			—			1,144,993
Income (loss) before income taxes	43,463			(3,441		)	1,054,602
Income tax benefit (expense)	—			—			—
Net income (loss)	43,463			(3,441		)	1,054,602
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
Diluted	$	2.89		$	(0.23	)	$	8.50

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

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
	September 30, 2017		September 30, 2016			September 12, 2016
Net income (loss)	$	43,463	$	(3,441	)	$	1,054,602
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016	—		—			(421		)
	—		—			(421		)
Comprehensive income (loss)	$	43,463	$	(3,441	)	$	1,054,181

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,
	2017		2016
Assets
Current assets
Cash and cash equivalents	$	7,487	$	6,761
Accounts receivable, net of allowance for doubtful accounts	48,096		29,095
Derivative assets	6,140		—
Other current assets	3,115		3,028
Total current assets	64,838		38,884
Property and equipment, net (full cost method)	486,060		247,473
Derivative assets	2,520		—
Other assets	8,823		5,329
Total assets	$	562,241	$	291,686

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	62,236	$	49,697
Derivative liabilities	13,634		12,932
Total current liabilities	75,870		62,629
Other liabilities	4,631		4,072
Derivative liabilities	4,923		14,437
Long-term debt, net	245,055		25,000

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
Paid-in capital	193,372		190,621
Retained earnings (accumulated deficit)	38,167		(5,296		)
Accumulated other comprehensive income	73		73
Total shareholders’ equity	231,762		185,548
Total liabilities and shareholders’ equity	$	562,241	$	291,686

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
	September 30, 2017			September 30, 2016			September 12, 2016
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		)
Depreciation, depletion and amortization	31,545			2,029			33,582
Accretion of firm transportation obligation	—			—			317
Derivative contracts:
Net (gains) losses	(15,802		)	4,369			8,333
Cash settlements, net	(1,670		)	—			48,008
Loss (gain) on sales of assets, net	60			—			(1,261		)
Non-cash exploration expense	—			—			6,038
Non-cash interest expense	1,362			38			22,188
Share-based compensation (equity-classified)	2,707			—			1,511
Other, net	59			—			(13		)
Changes in operating assets and liabilities, net	(11,430		)	585			35,244
Net cash provided by operating activities	50,294			3,580			30,247

Cash flows from investing activities
Acquisition, net	(200,162		)	—			—
Capital expenditures	(67,844		)	—			(15,359		)
Proceeds from sales of assets, net	—			—			224
Other, net	—			—			1,186
Net cash used in investing activities	(268,006		)	—			(13,949		)

Cash flows from financing activities
Proceeds from credit facility borrowings	39,000			—			75,350
Repayment of credit facility borrowings	(7,000		)	(21,000		)	(119,121		)
Proceeds from second lien facility, net	196,000			—			—
Debt issuance costs paid	(9,562		)	—			(3,011		)
Proceeds received from rights offering, net	55			—			49,943
Other, net	(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
Cash and cash equivalents – beginning of period	6,761			31,414			11,955
Cash and cash equivalents – end of period	$	7,487		$	13,994		$	31,414

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	1,596		$	—		$	4,331
Income taxes, net of (refunds)	$	—		$	—		$	(35	)
Reorganization items, net	$	1,098		$	—		$	30,990
Non-cash investing and financing activities:
Common stock issued in exchange for liabilities	$	—		$	—		$	140,952
Changes in accrued liabilities related to capital expenditures	$	8,140		$	—		$	(11,301	)
Derivatives settled to reduce outstanding debt	$	—		$	—		$	51,979

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2017

(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 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.

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.


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

Comparability of Financial Statements to Prior Periods

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 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 (“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. 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 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 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, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry.

In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“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.


3.	Acquisitions

Eagle Ford Acquisition

On 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 million in cash, subject to customary purchase price adjustments (the “Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Acquisition has 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.

On 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.

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

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 as a component of our “General and administrative” expenses.

We accounted for the 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, 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 fair values assigned to the net assets acquired as of the Date of Acquisition and the consideration transferred:



Assets
Oil and gas properties - proved	$	42,795
Oil and gas properties - unproved	142,817
Other property and equipment	8,642
Liabilities
Asset retirement obligations (“AROs”)	491
Net assets acquired	$	193,763

Cash consideration paid to Devon on the Date of Acquisition	$	189,911
Amount transferred to Devon from the Escrow Account	7,049
Application of working capital adjustments, net	(3,197		)
Preliminary purchase price	$	193,763

The fair values of the oil and gas properties acquired 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 and (v) 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.

The following table presents unaudited summary pro forma financial information for the periods presented assuming the Acquisition 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 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,
	2017			2017
Total revenues	$	41,865		$	130,504
Net income (loss) attributable to common shareholders	$	(8,657	)	$	38,947
Net income (loss) per share - basic	$	(0.58	)	$	2.60
Net income (loss) per share - diluted	$	(0.58	)	$	2.58


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”).

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 3, 2017, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of Successor common stock have been allocated, certain of these matters must be settled with cash payments. As of September 30, 2017, 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 Major Customers

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



	September 30,			December 31,
	2017			2016
Customers	$	30,852		$	20,489
Joint interest partners	18,938			7,238
Other	668			3,789
	50,458			31,516
Less: Allowance for doubtful accounts	(2,362		)	(2,421		)
	$	48,096		$	29,095

For the nine months ended September 30, 2017, two customers accounted for $85.9 million, or approximately 82%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2017 were $72.6 million and $13.3 million, or 69% and 13% of the consolidated total, respectively. As of September 30, 2017, $14.6 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 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%, 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.


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 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 30, 2017:



		Average	Weighted
		Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability
Crude Oil:		(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/Put option ¹	8,455	$	47.98	—		1,563
Fourth quarter 2018	Swaps/Put option ¹	8,455	$	47.98	—		1,251
First quarter 2019	Swaps	2,946	$	49.87	—		356
Second quarter 2019	Swaps	2,921	$	49.87	—		307
Third quarter 2019	Swaps	2,897	$	49.87	—		258
Fourth quarter 2019	Swaps	2,898	$	49.87	—		231
Settlements to be paid in subsequent period							172

_______________________

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	)

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
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	6,140	$	13,634	$	—	$	12,932
Commodity contracts	Derivative assets/liabilities – noncurrent	2,520		4,923		—		14,437
		$	8,660	$	18,557	$	—	$	27,369

As of September 30, 2017, we reported total commodity derivative assets of $8.7 million. The contracts associated with this position are with three 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,
	2017			2016
Oil and gas properties:
Proved	$	369,384		$	251,083
Unproved	147,594			4,719
Total oil and gas properties	516,978			255,802
Other property and equipment	12,484			3,575
Total properties and equipment	529,462			259,377
Accumulated depreciation, depletion and amortization	(43,402		)	(11,904		)
	$	486,060		$	247,473

Unproved property costs of $147.6 million and $4.7 million have been excluded from amortization as of September 30, 2017 and December 31, 2016, respectively. We transferred $1.9 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest, from unproved properties to the full cost pool during the nine months ended September 30, 2017. We capitalized internal costs of $1.6 million and interest of $0.1 million during the nine months ended September 30, 2017 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 for the nine months ended September 30, 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).


8.	Long-Term Debt

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



	September 30, 2017					December 31, 2016
	Principal			Unamortized Discount and Deferred Issuance Costs ¹		Principal		Unamortized Discount and Deferred Issuance Costs
Credit facility ²	$	57,000				$	25,000
Second lien term loans	200,000			$	11,945	—		$	—
Totals	257,000			$	11,945	25,000		$	—
Less: Unamortized discount	(4,000		)			—
Less: Unamortized deferred issuance costs	(7,945		)			—
Long-term debt, net	$	245,055				$	25,000

_______________________

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.


²	Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over it’s 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.

Credit Facility

On the Emergence Date, we entered into the Credit Facility. The Credit Facility currently provides for a $237.5 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In September 2017, the borrowing base under the Credit Facility was redetermined from $200 million to $237.5 million pursuant to the Master Assignment, Agreement and Amendment No. 3 to the Credit Facility (the “Third Amendment”). In the nine months ended September 30, 2017, we paid and capitalized issue costs of $1.7 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. 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 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 September 30, 2017 and December 31, 2016.

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 30, 2017, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.42%. 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 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 30, 2017, 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 million from the Second Lien Facility net of an original issue discount (“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 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.

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 30, 2017, we were in compliance with all of the covenants under the Second Lien Facility.


9.	Income Taxes

We recognized a federal and state income tax expense for the nine months ended September 30, 2017 at the blended rate of 35.52%; however, the federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets. We recognized a federal income tax benefit for the nine months ended September 30, 2016 at the statutory rate of 35% 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 a state income tax refund of less than $0.1 million during the nine months 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 (“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 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 are included as a component of our “General and administrative” 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.

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,
	2017		2016
Other current assets:
Tubular inventory and well materials	$	2,297	$	2,125
Prepaid expenses	818		903
	$	3,115	$	3,028
Other assets:
Deferred issuance costs of the Credit Facility	$	3,130	$	2,785
Deposit in escrow ¹	3,205		—
Other	2,488		2,544
	$	8,823	$	5,329
Accounts payable and accrued liabilities:
Trade accounts payable	$	7,275	$	9,825
Drilling costs	10,620		2,479
Royalties and revenue – related	30,184		26,116
Compensation – related	3,135		2,557
Interest	107		55
Reserve for bankruptcy claims	3,922		3,922
Other	6,993		4,743
	$	62,236	$	49,697
Other liabilities:
Asset retirement obligations	$	3,041	$	2,459
Defined benefit pension obligations	946		1,025
Postretirement health care benefit obligations	544		488
Other	100		100
	$	4,631	$	4,072

_______________________

¹ Represents amount remaining in the escrow deposit for the Acquisition (see Note 3).


12.	Fair Value Measurements

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

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility and Second Lien Facility borrowings. As of September 30, 2017, 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
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1		Level 2			Level 3
Assets:
Commodity derivative assets – current	$	6,140		$	—	$	6,140		$	—
Commodity derivative assets – noncurrent	2,520			—		2,520			—
Liabilities:
Commodity derivative liabilities – current	$	(13,634	)	$	—	$	(13,634	)	$	—
Commodity derivative liabilities – noncurrent	(4,923		)	—		(4,923		)	—



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

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 ended September 30, 2017 and 2016.

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 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 2 input.

Non-Recurring Fair Value Measurements

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

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 to Republic, or 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 are as follows: $2.5 million for the remainder of 2017, $10.4 million for 2018, $11.7 million for 2019, $13.0 million for 2020 through 2025, $7.4 million for 2026, $3.8 million for 2027 through 2030 and $2.2 million for 2031.

Drilling Commitments

We have contractual commitments for three drilling rigs. One rig began operations in September 2017 and is subject to a six-month commitment through March 2018. A second rig began operations in October 2017 and is committed on a limited well pad-basis. A third rig is contracted to enter service in November 2017 and is also subject to a six-month commitment through May 2018. We have approximately $6.9 million of obligations associated with these commitments.

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of September 30, 2017, we continue to maintain a $0.1 million reserve for a litigation matter. As of September 30, 2017, we also had AROs of approximately $3.0 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 months ended September 30, 2017:



	December 31,					All Other		September 30,
	2016			Net Income		Changes ¹		2017
Common stock	$	150		$	—	$	—	$	150
Paid-in capital	190,621			—		2,751		193,372
Retained earnings (accumulated deficit)	(5,296		)	43,463		—		38,167
Accumulated other comprehensive income	73			—		—		73
	$	185,548		$	43,463	$	2,751	$	231,762

_______________________

¹ Includes equity-classified share-based compensation of $2.7 million and $0.1 million from 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. During the nine months ended September 30, 2017, 12,252 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs“ ), net of shares withheld for income taxes.


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 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 for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 298,454 RSUs and 98,526 performance restricted stock units (“PRSUs”) have been granted as of September 30, 2017.

The following table summarizes our share-based compensation expense (benefit) recognized 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 for the 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

In the nine months ended September 30, 2017, we granted 190,891 RSUs to certain employees with an average grant-date fair value of $48.70 per RSU. The RSUs are being charged to expense on a straight-line basis over five years. In the nine months ended September 30, 2017, we also granted 98,526 PRSUs to members of our management. The 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 $0.3 million of expense attributable to the 401(k) Plan for the nine months ended September 30, 2017, and $0.4 million for the period January 1, 2016 through September 12, 2016, and less than $0.1 million for the period September 13, 2016 through September 30, 2016.

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 the nine months ended September 30, 2017, less than $0.1 million 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.


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

___________________

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 attributable 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 Credit 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			Period From September 13, 2016			Period From July 1, 2016
	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

Weighted-average shares – basic	14,994			14,992			89,292
Effect of dilutive securities ¹	—			—			22,166
Weighted-average shares – diluted	14,994			14,992			111,458

_______________________

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 30, 2017, approximately 0.1 million of potentially dilutive securities attributable to RSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted loss 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. 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, including our ability to realize its 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 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 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, NGLs and natural gas;


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


•	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 estimated proved oil and 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;


•	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 of these parties to meet their future obligations;


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


•	physical, electronic and cybersecurity breaches;


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


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


•	other factors set forth in our 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.

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.

Overview and Executive Summary

We are an independent oil and gas company engaged in the onshore exploration, development and production of 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 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 oil prices have recovered somewhat from recent historically low levels of less than $30 per barrel, or Bbl, in February 2016, they remain generally depressed due to domestic and global supply and demand factors compared to the period from 2009 through 2014 when we initially began our expansion into the Eagle Ford. Similarly, the costs for drilling, completion and general 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 to recover and expand.

As discussed in Note 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 2 to the Condensed Consolidated Financial Statements, we have 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.

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


•	Production declined approximately seven percent to 864 thousand barrels of oil equivalent, or MBOE, from 925 MBOE due primarily to anticipated staging delays in our drilling program that were exacerbated by Hurricane Harvey, mechanical issues with our previously-contracted drilling rigs and production curtailments attributable to the storm.


•	Product revenues declined approximately five percent to $34.3 million from $36.3 million due to lower crude oil and NGL volumes partially offset by higher natural gas volumes and higher pricing for all commodity products.


•	Production and lifting costs declined on an absolute basis to $7.6 million from $7.9 million, but increased on a per unit basis to $8.85 per barrel of oil equivalent, or BOE, from $8.58 per BOE due primarily to the decrease in production volume.


•	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 million and $8.04 per BOE from $3.7 million and $4.03 per BOE, respectively, due primarily to $1.5 million of transaction costs associated with the Acquisition, $0.2 million of costs incurred to complete an upgrade of our ERP system and higher compensation and employee-related support costs as we have expanded our employee base commensurate with our current growth plans as well as the effect of lower production volume.


•	Our operating income declined to $7.5 million for the three months ended September 30, 2017 compared to $11.4 million for the three months ended June 30, 2017 due the combined impact of the matters noted 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
	September 30,			June 30,			September 30,			September 30,			September 12,			September 12,
	2017			2017			2017			2016			2016			2016
Total production (MBOE)	864			925			2,644			183			796			3,346
Average daily production (BOEPD)	9,396			10,159			9,683			10,145			10,752			13,071
Crude oil production (MBbl)	627			685			1,920			127			547			2,311
Crude oil production as a percent of total	73		%	74		%	73		%	70		%	69		%	69		%
Product revenues	$	34,333		$	36,274		$	105,325		$	6,316		$	26,961		$	93,649
Crude oil revenues	$	29,963		$	32,351		$	92,387		$	5,508		$	23,392		$	81,377
Crude oil revenues as a percent of total	87		%	89		%	88		%	87		%	87		%	87		%
Realized prices:
Crude oil ($ per Bbl)	$	47.78		$	47.25		$	48.12		$	43.35		$	42.75		$	35.21
NGLs ($ per Bbl)	$	19.19		$	15.59		$	17.98		$	12.56		$	12.66		$	11.37
Natural gas ($ per Mcf)	$	2.92		$	2.88		$	2.96		$	2.73		$	2.72		$	2.06
Aggregate ($ per BOE)	$	39.72		$	39.24		$	39.84		$	34.59		$	33.89		$	27.99
Prices adjusted for derivatives:
Crude oil ($ per Bbl)	$	49.04		$	46.57		$	47.25		$	43.35		$	44.68		$	55.98
Aggregate ($ per BOE)	$	40.63		$	38.73		$	39.21		$	34.59		$	35.21		$	42.33
Production and lifting costs:
Lease operating ($ per BOE)	$	6.07		$	5.81		$	5.88		$	4.13		$	5.29		$	4.67
Gathering, processing and transportation ($ per BOE)	$	2.77		$	2.77		$	2.84		$	3.15		$	6.00		$	3.96
Production and ad valorem taxes ($ per BOE)	$	1.93		$	2.29		$	2.18		$	2.05		$	0.72		$	1.04
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
Cash and cash equivalents at end of period				$	10,105		$	7,487		$	13,994					$	31,414
Debt outstanding at end of period, net				$	37,000		$	245,055		$	54,350					$	1,187,553
Credit available under credit facility at end of period ⁴				$	162,245		$	179,745		$	72,883					$	—
Net development wells drilled and completed	5.0			3.0			11.6			—			—			2.9

^{__________________________________________________________________________________}

Includes combined amounts of $3.15 and $0.92 per BOE for the three-month periods ended September 30, and June 30, 2017, $1.67 per BOE for the nine months ended September 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 and $6.98 per BOE for the period from January 1 through September 12, 2016, respectively, attributable to equity-classified share-based compensation, liability-classified share-based compensation and significant special charges, including strategic and financial advisory 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 and $48.0 million for the three-month period ended September 30, 2017, the period from July 1, 2016 through September 12, 2016 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.


⁴	As of September 12, 2016, we were unable to draw on our pre-petition credit facility, or RBL.

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 to Executive Management

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, we entered into a purchase and sale agreement, or the Purchase Agreement, with Devon Energy Corporation, or Devon, to acquire all of Devon’s right, title and interest 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, and closed 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 Devon 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 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.

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

Production and Development Plans

Total production for the third quarter of 2017 was 864 MBOE, or 9,396 barrels of oil equivalent per day, or BOEPD, with approximately 73 percent, or 627 MBOE, of production from crude oil, 14 percent from NGLs and 13 percent from natural gas. Production from our Eagle Ford operations during this period was 785 MBOE or 8,535 BOEPD. Approximately 78 percent of our Eagle Ford production for the period was from crude oil, 12 percent was from NGLs and 10 percent was from natural gas. Production from our Eagle Ford operations was approximately 91 percent of total Company production during the third quarter of 2017.

We drilled and turned seven gross (five net) Eagle Ford wells to sales during the third quarter completing operations on our Chicken Hawk and Jake Berger pads. Our average working interest in the Chicken Hawk and Jake Berger pads are approximately 76 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. The associated downtime resulted in delays and contributed 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 to the Condensed Consolidated Financial Statements). In addition, the impact of Hurricane Harvey resulted in delays to our planned drilling schedule 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. Two of the new rigs are currently drilling wells on the Furrh pad located 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 3, 2017, including the effect of additional hedge contracts that we entered into or otherwise modified in October 2017, 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 with a weighted-average swap price of $48.59 per barrel based on the West Texas Intermediate, or WTI, index 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. We are currently unhedged with respect to NGL and natural gas production.

Financial Condition

Liquidity

Our primary sources of liquidity include cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to $237.5 million in borrowing commitments. The current borrowing base under the Credit Facility is also $237.5 million. As of November 3, 2017, we had outstanding borrowings and letters of credit of $61.0 million and $0.8 million, respectively, resulting in $175.7 million of availability 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 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, we currently anticipate capital expenditures, excluding the Acquisition, to total between $120 million and $140 million for 2017, with approximately 95 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our 2017 capital spending with cash from operating activities and borrowings under the Credit Facility. Based upon current price and production expectations for 2017, 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; 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 3, 2017, we had approximately $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 borrowed $75.4 million under the Credit Facility upon our emergence from bankruptcy in September 2016. Since that time we have paid down $14.4 million, net of new borrowings through November 3, 2017. 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 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	%

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
	September 30,			September 30,			September 12,
	2017			2016			2016
Cash flows from operating activities
Operating cash flows, net of working capital changes	$	54,272		$	4,782		$	34,731
Crude oil derivative settlements (paid) received, net	(1,670		)	—			48,008
Interest payments, net of amounts capitalized	(1,596		)	—			(4,148		)
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		)
Net cash provided by operating activities	50,294			3,580			30,247
Cash flows from investing activities
Acquisition, net	(200,162		)	—			—
Capital expenditures	(67,844		)	—			(15,359		)
Proceeds from sales of assets, net	—			—			224
Other, net	—			—			1,186
Net cash used in investing activities	(268,006		)	—			(13,949		)
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			—			—
Debt issuance costs paid	(9,562		)	—			(3,011		)
Proceeds received from rights offering, net	55			—			49,943
Other, net	(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

Cash Flows from Operating Activities. The overall increase in net cash from operating for the nine months ended September 30, 2017 compared to the corresponding period from the combined Successor and Predecessor periods in 2016 was primarily attributable to (i) higher pricing resulting in higher overall product revenue receipts in the 2017 period, (ii) substantially higher payments 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 Predecessor period and (iv) lower interest payments due to lower outstanding borrowings under the Credit Facility in the 2017 period as compared to outstanding borrowings under the RBL 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 Predecessor 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 associated with the Acquisition in the 2017 period and (ii) experienced higher working capital utilization in 2017 as a result of the restart of our drilling program, which had been suspended in February 2016.

Cash Flows from Investing Activities. In the 2017 period, we paid a total of $200.2 million for the Acquisition which included $189.9 million paid to Devon on the Date of Acquisition and $10.3 million paid into the Escrow Account in July 2017. As illustrated in the tables below, our cash payments for capital expenditures were higher during the 2017 period as compared 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 in the Predecessor period in 2016 includes a higher portion attributable to settlements of accrued capital charges from the prior year-end period. The Predecessor period in 2016 also includes insurance recoveries from a casualty loss incurred in 2015.

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
	September 30,			September 30,		September 12,
	2017			2016		2016
Drilling and completion	$	72,263		$	—	$	3,696
Lease acquisitions and other land-related costs	2,094			—		58
Pipeline, gathering facilities and other equipment, net	(703		)	—		375
Geological, geophysical (seismic) and delay rental costs	508			—		(16		)
	$	74,162		$	—	$	4,113

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
	September 30,			September 30,		September 12,
	2017			2016		2016
Total capital expenditures program costs (from above)	$	74,162		$	—	$	4,113
(Increase) decrease in accrued capitalized costs	(8,140		)	—		11,301
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		)
Add:
Tubular inventory and well materials purchased in advance of drilling	2,657			—		211
Capitalized internal labor ¹	1,614			—		—
Capitalized interest	132			—		183
Total cash paid for capital expenditures	$	67,844		$	—	$	15,359

^{__________________________________________________________________________________}


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 period includes borrowings of $39 million and repayments of $7 million under the Credit Facility while the Predecessor period in 2016 includes 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. We also paid $1.7 million of debt issue costs in 2017 in connection with amendments to the Credit Facility and $7.9 million in connection with the Second Lien Facility. Delayed receipts attributable to the rights offering in September 2016 were offset by costs paid in connection with the registration of our common stock in the Successor period in 2017.

Capitalization

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



	September 30,			December 31,
	2017			2016
Credit Facility borrowings	$	57,000		$	25,000
Second Lien Facility term loans	188,055			—
Total debt	245,055			25,000
Shareholders’ equity	231,762			185,548
	$	476,817		$	210,548
Debt as a % of total capitalization	51		%	12		%

Credit Facility. Following the Third Amendment, the Credit Facility provides for a $237.5 million revolving commitment and borrowing base. The Credit Facility includes a $5 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 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.

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 30, 2017, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.42%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by our parent company 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 no material independent assets or operations. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets.

Second Lien Facility. 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 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%. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our election and is computed on the basis of a 360- day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: during years one and two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.

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. 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 30, 2017, 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 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 decreased during the three and nine month periods in 2017 when compared to the corresponding combined Successor and Predecessor periods in 2016 due primarily to the suspension of our drilling program in February 2016 and natural production declines. While we resumed the 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.

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
	Revenue Variance Due to								Revenue Variance Due to
	Volume			Price		Total			Volume			Price		Total
Crude oil	$	(2,016	)	$	3,079	1,063			$	(18,456	)	$	23,958	5,502
NGLs	(437		)	817		380			(2,114		)	2,455		341
Natural gas	(522		)	135		(387		)	(2,284		)	1,801		(483		)
	$	(2,975	)	$	4,031	$	1,056		$	(22,854	)	$	28,214	$	5,360

Our product revenues during the three and nine month periods in 2017 increased over the corresponding combined Successor and Predecessor periods in 2016 due primarily to the significant increases in all product pricing which was somewhat offset by the decline in production described previously. Total crude oil revenues were approximately 87 percent during each of the three month period in 2017 and the combined Successor and Predecessor three month period in 2016. Total Eagle Ford revenues were approximately 95 percent of total revenues for each of the three and nine month periods in 2017 and 95 percent and 94 percent for each of the corresponding combined Successor and Predecessor periods in 2016, respectively.

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
	September 30,		September 30,		September 12,		September 30,			September 30,		September 12,
	2017		2016		2016		2017			2016		2016
Crude oil revenues, as reported	$	29,963	$	5,508	$	23,392	$	92,387		$	5,508	$	81,377
Derivative settlements, net	788		—		1,056		(1,670		)	—		48,008
	$	30,751	$	5,508	$	24,448	$	90,717		$	5,508	$	129,385

Crude oil prices per Bbl	$	47.78	$	43.35	$	42.75	$	48.12		$	43.35	$	35.21
Derivative settlements per Bbl	1.26		—		1.93		(0.87		)	—		20.77
	$	49.04	$	43.35	$	44.68	$	47.25		$	43.35	$	55.98

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 the total gains and losses recognized 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
Gain (loss) on sales of assets, net	$	9	$	—	$	504	$	(60	)	$	—	$	1,261

There were insignificant net gains and losses recognized during the three and nine month periods in 2017 attributable to 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:



	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
Other revenues, net	$	117	$	33	$	(804	)	$	462	$	33	$	(600	)

Other revenues, net increased during the three and nine month periods in 2017 from the corresponding combined Successor and Predecessor periods in 2016 due primarily to higher marketing fees partially offset by lower water disposal 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.

Lease Operating Expense

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.



	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
Lease operating	$	5,254	$	756	$	4,209		$	15,540	$	756	$	15,626
Per unit of production ($/BOE)	$	6.07	$	4.13	$	5.29		$	5.88	$	4.13	$	4.67
% Change per unit of production					(19		)%					(27		)%

LOE increased on a per unit basis during the three and nine month periods in 2017 when compared to the corresponding combined Successor and Predecessor periods in 2016 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 production volume, as well as higher surface and other repair and maintenance costs. We proceeded with certain of these repair and maintenance efforts during the third quarter of 2017 in order to recover a portion of the production shortfall brought about by Hurricane Harvey and operational delays discussed above. While we incurred higher such repair costs in the three and nine month periods in 2017, they were partially offset by continuing cost containment efforts that we implemented throughout 2016 and into 2017 as well as the effects of lower industry-wide pricing for certain oilfield products and services.

Gathering, Processing and Transportation

Gathering, processing and transportation, or GPT, includes costs that we incur to gather and aggregate our oil, NGL and natural gas production from our wells and deliver them to a central delivery point, downstream pipelines or processing plants, depending upon the type of production and the specific arrangements that we have with midstream operators.



	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
Gathering, processing and transportation	$	2,399	$	576	$	4,767		$	7,505	$	576	$	13,235
Per unit of production ($/BOE)	$	2.77	$	3.15	$	6.00		$	2.84	$	3.15	$	3.96
% Change per unit of production					49		%					27		%

GPT decreased during the three and nine month periods in 2017 when compared to the corresponding combined Successor and Predecessor periods in 2016 due primarily to substantially lower production volumes as discussed above and the effect of an amendment to our gathering agreement with Republic Midstream, LLC that became effective in August of 2016. 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 in the combined Successor 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 as the underlying contracts were rejected in our bankruptcy proceedings.

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.



	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
Production and ad valorem taxes
Production/severance taxes	$	1,643		$	288		$	1,315		$	4,996		$	288		$	2,695
Ad valorem taxes	25			87			(741		)	770			87			795
	$	1,668		$	375		$	574		$	5,766		$	375		$	3,490
Per unit production ($/BOE)	$	1.93		$	2.05		$	0.72		$	2.18		$	2.05		$	1.04
Production/severance tax rate as a percent of product revenue	4.8		%	4.6		%	4.9		%	4.7		%	4.6		%	2.9		%

Production taxes increased on both an absolute and per unit basis during the three and nine month periods in 2017 when compared to the corresponding combined Successor and Predecessor periods in 2016 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 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 for ad valorem taxes downward, primarily in South Texas, reflecting lower oil and gas property valuations.

General and Administrative

Our general and administrative 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 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, 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.

Our primary G&A expenses decreased on an absolute and per unit basis during the three and nine month periods in 2017 compared to the corresponding combined Successor and Predecessor periods in 2016. The decrease is due primarily to the effects of: (i) lower payroll and benefits attributable to a lower overall employee headcount, partially offset by costs associated with recent hires consistent with our current growth plans (ii) the capitalization 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 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 favorable during the 2016 periods resulting in a mark-to-market reversal. All of the unvested PBRSUs were canceled upon our emergence from bankruptcy.

Equity-classified share-based compensation charges during the period in 2017 are attributable to 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. The 2017 grants of RSUs and PRSUs are described in greater detail in Note 15 to the Condensed Consolidated Financial Statements. The 2016 periods include a charge for the cancellation of all of the RSUs outstanding prior to our bankruptcy filing in May 2016, partially offset by forfeitures of the Predecessor’s stock options. All of our equity-classified share-based compensation represents non-cash expenses.

During the third quarter of 2017, we incurred transaction costs associated with the Acquisition, including advisory, legal, due diligence and other professional fees as well as certain costs associated with an upgrade 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 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 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 Note 7 to the Condensed Consolidated Financial Statements for a discussion of certain capitalized costs. The following table sets forth the components of exploration expense for the Predecessor 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
Unproved leasehold amortization	$	—	$	—	$	227	$	—	$	—	$	1,940
Drilling rig termination charges	—		—		279		—		—		1,705
Drilling carry commitment	—		—		—		—		—		1,964
Geological and geophysical costs	—		—		—		—		—		33
Other, primarily delay rentals	—		—		4,135		—		—		4,646
	$	—	$	—	$	4,641	$	—	$	—	$	10,288

In addition 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 in connection with the release of a drilling rig 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.

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:



	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
DD&A expense	$	10,659	$	2,029	$	8,024	$	31,545	$	2,029	$	33,582
DD&A Rate ($/BOE)	$	12.32	$	11.09	$	10.09	$	11.93	$	11.09	$	10.04

The effects of higher depletion rates resulted in higher DD&A during the three months ended September 30, 2017 when compared to the corresponding combined Successor and Predecessor period in 2016. Lower production volumes net of the effects of higher depletion rates were the primary factors 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 periods when compared to the Predecessor periods.

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
	September 30,			September 30,		September 12,		September 30,			September 30,		September 12,
	2017			2016		2016		2017			2016		2016
Interest on borrowings and related fees	$	880		$	180	$	1,363	$	1,785		$	180	$	36,013
Amortization of debt issuance costs	374			38		—		1,362			38		22,188
Capitalized interest	(52		)	—		—		(133		)	—		(183		)
	$	1,202		$	218	$	1,363	$	3,014		$	218	$	58,018

Interest expense during the three and nine month periods in 2017 is primarily attributable to the Credit Facility along with two days of interest attributable to the Second Lien Facility. Interest expense during the corresponding combined Successor and Predecessor periods in 2016 is attributable to the RBL 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 of debt issuance costs in the three and nine month periods in 2017 included write-offs of $0.2 million and $0.8 million attributable to previously capitalized debt issue costs due to changes 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.

Derivatives

The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio, by commodity type, 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
Crude oil derivative gains (losses)	$	(12,275	)	$	(4,369	)	$	8,934	$	15,802	$	(4,369	)	$	(8,333	)
Natural gas derivative gains (losses)	—			—			—		—		—			—
	$	(12,275	)	$	(4,369	)	$	8,934	$	15,802	$	(4,369	)	$	(8,333	)

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. We received cash settlements of $0.8 million and paid cash settlements of $1.7

million in the three and nine-month periods in 2017 as compared to the receipt of $1.1 million and $48.0 million of cash settlements from crude oil derivatives during the corresponding combined Successor and Predecessor periods in 2016. The changes in total cash settlements are 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 and Predecessor periods 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 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

The following table sets forth the other income (expense), net recognized 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
Other, net	$	3	$	9	$	(2,154	)	$	104	$	9	$	(3,184	)

In the periods in 2017, we recorded interest income and we recovered certain costs attributable to assets that were sold 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.

Reorganization Items, net

The following table summarizes the components included in Reorganization items, net 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

Reorganization items, net includes costs incurred in connection with the Predecessor’s bankruptcy proceedings including professional fees for attorneys, financial consultants, claims processors 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:



	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
Income tax benefit (expense)	$	—		$	—		$	—		$	—		$	—		$	—
Effective tax rate	—		%	—		%	—		%	—		%	—		%	—		%

We recognized a federal and state income tax expense for the three and nine month periods in 2017 at the blended rate of 35.52%; however, the federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets. We recognized a federal income tax benefit for the corresponding combined Successor and Predecessor periods in 2016 at the statutory rate of 35% 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 30, 2017, we had no off-balance sheet arrangements other than lease arrangements, information technology licensing, service agreements, employment agreements 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.

Disclosure of the Impact of Recently Issued Accounting Standards to be Adopted in the Future

In March 2017, 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. 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 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 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, land easements and similar arrangements for rights-of-way and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. We are also continuing to monitor developments regarding ASU 2016–02 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 for smaller reporting companies.


Item 4.	Controls and Procedures.

(a) Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2017. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2017, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2017, 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.

On August 11, 2016, the Bankruptcy Court confirmed our Plan, 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.


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.


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)

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

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