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 
or
¨
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
  image0a04.jpg
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
 
Condensed Consolidated Statements of Comprehensive Income
 
Condensed Consolidated Balance Sheets
 
Condensed Consolidated Statements of Cash Flows
 
Notes to Condensed Consolidated Financial Statements:
 
 
1. Nature of Operations
 
2. Basis of Presentation
 
3. Acquisitions
 
4. Bankruptcy Proceedings and Emergence
 
5. Accounts Receivable and Major Customers
 
6. Derivative Instruments
 
7. Property and Equipment
 
8. Long-Term Debt
 
9. Income Taxes
 
10. Exit Activities
 
11. Additional Balance Sheet Detail
 
12. Fair Value Measurements
 
13. Commitments and Contingencies
 
14. Shareholders’ Equity
 
15. Share-Based Compensation and Other Benefit Plans
 
16. Interest Expense
 
17. Earnings (Loss) per Share
Forward-Looking Statements
2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
 
Overview and Executive Summary
 
Key Developments
 
Financial Condition
 
Results of Operations
 
Critical Accounting Estimates
3.
Quantitative and Qualitative Disclosures About Market Risk.
4.
Controls and Procedures.
Part II - Other Information
1.
Legal Proceedings.
1A.
Risk Factors.
6.
Exhibits.
Signatures




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.

3



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.


4



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.

5



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.

6



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.

7



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.

8



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,

9



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


10



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



11



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).

12



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

_______________________
1
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


13



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.

14



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.
The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00%. Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.86%. 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

15



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.

16



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.

17



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.

18



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.

19



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.

20



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 costs 2
374

 
38

 
 

Capitalized interest
(51
)
 

 
 

 
$
1,202

 
$
218

 
 
$
1,363

___________________
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 $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.
2
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.


21



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

_______________________
1
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.


22



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.

23



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.

24



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