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, 2015 
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
 
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)
FOUR RADNOR CORPORATE CENTER, SUITE 200
100 MATSONFORD ROAD
RADNOR, PA 19087
(Address of principal executive offices) (Zip Code)
(610) 687-8900
(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)
__________________________________________________________
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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer
ý
Accelerated filer
o
Non-accelerated filer
o
Smaller reporting company
o
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
 As of November 6, 2015, 73,357,172 shares of common stock of the registrant were outstanding.
 




PENN VIRGINIA CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
 For the Quarterly Period Ended September 30, 2015
 Table of Contents
Part I - Financial Information
Item
 
Page
1.
Financial Statements:
 
 
Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2015 and 2014
 
Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2015 and 2014
 
Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014
 
Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2015 and 2014
 
Notes to Condensed Consolidated Financial Statements:
 
 
1. Organization
 
2. Basis of Presentation
 
3. Divestitures
 
4. Accounts Receivable and Major Customers
 
5. Derivative Instruments
 
6. Property and Equipment
 
7. Long-Term Debt
 
8. Income Taxes
 
9. Firm Transportation Obligation
 
10. Additional Balance Sheet Detail
 
11. Fair Value Measurements
 
12. Commitments and Contingencies
 
13. Shareholders’ Equity
 
14. Share-Based Compensation
 
15. Interest Expense
 
16. Earnings 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 AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS unaudited
(in thousands, except per share data) 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Revenues
 
 
 
 
 
 
 
Crude oil
$
51,124

 
$
118,716

 
$
180,964

 
$
336,382

Natural gas liquids (NGLs)
3,254

 
9,790

 
13,841

 
27,200

Natural gas
6,312

 
13,354

 
22,143

 
47,859

Gain on sales of property and equipment, net
50,828

 
63,520

 
50,803

 
120,295

Other, net
466

 
16

 
2,376

 
2,886

Total revenues
111,984

 
205,396

 
270,127

 
534,622

Operating expenses
 
 
 
 
 
 
 
Lease operating
11,304

 
14,761

 
33,780

 
36,878

Gathering, processing and transportation
5,654

 
5,428

 
19,535

 
12,605

Production and ad valorem taxes
3,483

 
7,690

 
13,139

 
22,505

General and administrative
9,416

 
11,527

 
32,865

 
43,055

Exploration
1,673

 
1,986

 
11,922

 
13,995

Depreciation, depletion and amortization
76,850

 
71,999

 
253,056

 
215,623

Impairments

 
6,084

 
1,084

 
123,992

Total operating expenses
108,380

 
119,475

 
365,381

 
468,653

Operating income (loss)
3,604

 
85,921

 
(95,254
)
 
65,969

Other income (expense)
 
 
 
 
 
 
 
Interest expense
(22,985
)
 
(21,953
)
 
(68,021
)
 
(67,716
)
Derivatives
44,701

 
66,457

 
52,073

 
8,130

Other
(44
)
 
1,349

 
(586
)
 
1,380

Income (loss) before income taxes
25,276

 
131,774

 
(111,788
)
 
7,763

Income tax (expense) benefit
624

 
(42,113
)
 
394

 
339

Net income (loss)
25,900

 
89,661

 
(111,394
)
 
8,102

Preferred stock dividends
(5,935
)
 
(7,641
)
 
(18,069
)
 
(11,081
)
Induced conversion of preferred stock

 
(888
)
 

 
(4,256
)
Net income (loss) attributable to common shareholders
$
19,965

 
$
81,132

 
$
(129,463
)
 
$
(7,235
)
Net income (loss) per share:
 
 
 
 
 
 
 
Basic
$
0.27

 
$
1.13

 
$
(1.79
)
 
$
(0.11
)
Diluted
$
0.25

 
$
0.87

 
$
(1.79
)
 
$
(0.11
)
 
 
 
 
 
 
 
 
Weighted average shares outstanding – basic
72,651

 
71,536

 
72,438

 
67,909

Weighted average shares outstanding – diluted
103,452

 
103,606

 
72,438

 
67,909


See accompanying notes to condensed consolidated financial statements.

3



PENN VIRGINIA CORPORATION AND SUBSIDIARIES 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME unaudited
(in thousands) 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss)
$
25,900

 
$
89,661

 
$
(111,394
)
 
$
8,102

Other comprehensive income (loss):
 

 
 

 
 
 
 
Change in pension and postretirement obligations, net of tax of $(6) and $(17) in 2015 and $14 and $40 in 2014
(11
)
 
25

 
(32
)
 
74

 
(11
)
 
25

 
(32
)
 
74

Comprehensive income (loss)
$
25,889

 
$
89,686

 
$
(111,426
)
 
$
8,176

 
See accompanying notes to condensed consolidated financial statements.

4



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS unaudited
(in thousands, except share data)
 
As of
 
September 30,
 
December 31,
 
2015
 
2014
Assets
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
3,342

 
$
6,252

Accounts receivable, net of allowance for doubtful accounts
73,020

 
189,627

Derivative assets
96,211

 
128,981

Deferred income taxes

 
53

Other current assets
7,302

 
10,114

Total current assets
179,875

 
335,027

Property and equipment, net (successful efforts method)
1,818,586

 
1,825,098

Derivative assets
16,149

 
35,897

Other assets
5,836

 
5,841

Total assets
$
2,020,446

 
$
2,201,863

 
 
 
 
Liabilities and Shareholders’ Equity
 

 
 

Current liabilities
 

 
 

Accounts payable and accrued liabilities
$
161,908

 
$
312,227

Derivative liabilities

 

Total current liabilities
161,908

 
312,227

Other liabilities
105,237

 
123,886

Deferred income taxes
4,868

 
4,504

Long-term debt, net of unamortized issuance costs
1,193,362

 
1,085,429

 
 
 
 
Commitments and contingencies (Note 12)


 


 
 
 
 
Shareholders’ equity:
 

 
 

Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,070 shares and 7,945 shares issued as of September 30, 2015 and December 31, 2014, respectively, and Series B – 32,500 shares issued as of September 30, 2015 and December 31, 2014, each with a redemption value of $10,000 per share
3,957

 
4,044

Common stock of $0.01 par value – 228,000,000 shares authorized; 73,297,205 and 71,568,936 shares issued as of September 30, 2015 and December 31, 2014, respectively
548

 
529

Paid-in capital
1,209,187

 
1,206,305

Accumulated deficit
(658,704
)
 
(535,176
)
Deferred compensation obligation
3,440

 
3,211

Accumulated other comprehensive income
217

 
249

Treasury stock – 455,689 and 262,070 shares of common stock, at cost, as of September 30, 2015 and December 31, 2014, respectively
(3,574
)
 
(3,345
)
Total shareholders’ equity
555,071

 
675,817

Total liabilities and shareholders’ equity
$
2,020,446

 
$
2,201,863


See accompanying notes to condensed consolidated financial statements.

5



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS unaudited
(in thousands)
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Cash flows from operating activities
 

 
 

Net income (loss)
$
(111,394
)
 
$
8,102

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
253,056

 
215,623

Impairments
1,084

 
123,992

Accretion of firm transportation obligation
705

 
991

Derivative contracts:
 
 
 
Net gains
(52,073
)
 
(8,130
)
Cash settlements, net
104,590

 
(17,836
)
Deferred income tax expense (benefit)
266

 
(339
)
Gain on sales of assets, net
(50,803
)
 
(120,295
)
Non-cash exploration expense
4,903

 
8,387

Non-cash interest expense
3,504

 
3,114

Share-based compensation (equity-classified)
3,369

 
2,638

Other, net
(17
)
 
325

Changes in operating assets and liabilities, net
5,051

 
(16,122
)
Net cash provided by operating activities
162,241

 
200,450

 
 
 
 
Cash flows from investing activities
 

 
 

Receipts to settle working capital adjustments assumed in acquisition, net

 
33,712

Capital expenditures – property and equipment
(324,876
)
 
(545,031
)
Proceeds from sales of assets, net
73,670

 
311,913

Net cash used in investing activities
(251,206
)
 
(199,406
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from the issuance of preferred stock, net

 
313,330

Payments made to induce conversion of preferred stock

 
(4,256
)
Proceeds from revolving credit facility borrowings
203,000

 
377,000

Repayment of revolving credit facility borrowings
(98,000
)
 
(583,000
)
Debt issuance costs paid
(744
)
 
(151
)
Dividends paid on preferred stock
(18,201
)
 
(5,165
)
Other, net

 
1,414

Net cash provided by financing activities
86,055

 
99,172

Net (decrease) increase in cash and cash equivalents
(2,910
)
 
100,216

Cash and cash equivalents – beginning of period
6,252

 
23,474

Cash and cash equivalents – end of period
$
3,342

 
$
123,690

 
 
 
 
Supplemental disclosures:
 

 
 

Cash paid for:
 

 
 

Interest
$
47,489

 
$
47,778

Income taxes
$
7

 
$
100

Non-cash investing activities:
 
 
 
Changes in accrued liabilities related to capital expenditures
$
(41,800
)
 
$
12,805

 
See accompanying notes to condensed consolidated financial statements.

6



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS unaudited
For the Quarterly Period Ended September 30, 2015
(in thousands, except per share amounts)

1. 
Organization
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 in the Eagle Ford Shale in South Texas. We also have less significant operations in Oklahoma, primarily the Granite Wash.

2.
Basis of Presentation
Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. 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, 2014. Operating results for the nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheet or cash flows.
Going Concern Presumption and Management’s Plans
These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. We have incurred net losses in each of the three years ending December 31, 2014, and reported a net loss attributable to common shareholders of $(129.5) million for the nine months ended September 30, 2015. While we were in compliance with the covenants of our revolving credit agreement (the “Revolver”) as of September 30, 2015, based on our current operating forecast and capital structure, we do not believe we will be able to comply with all of the covenants under the Revolver during the next twelve months. We are also dependent on obtaining additional debt and/or equity financing to continue our planned principal business operations. These factors raise substantial doubt about our ability to continue as a going concern.
Management’s plans in regard to these matters consist principally of restructuring our debt or seeking additional debt or equity funding from outside sources. We are actively working to address these matters, however, there can be no assurance that our efforts will be successful. The Condensed Consolidated Financial Statements do not include any adjustments that may result from the outcome of this uncertainty.
Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products, as well as variations in our production. Due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:
We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period (see Note 12). We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.
We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015 (see Note 3).
We suspended the payment of dividends on our convertible preferred stock in September 2015 (see Note 13).
We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015 (see Note 3).
We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.
We engaged Jefferies LLC (“Jefferies”) to advise us with respect to asset-level financing transactions and various financing and debt restructuring options (see Note 12).

7



While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior subordinated notes become due in April and May of 2016. Moreover, unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016.
Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection.
Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.
New Accounting Pronouncements
Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015–03”) on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10) as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).
In 2014, the FASB issued ASU No. 2014–09, Revenue 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 U.S. GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, that defers by one year the effective date of ASU 2014–09 to fiscal years beginning after December 17, 2017, or calendar year 2018 for us. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014–09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014–09 on our ongoing financial reporting.
Subsequent Events
Management has evaluated all activities of the Company through the date upon which our Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of non-core properties in the southwestern portion of our Eagle Ford acreage referenced above and in Note 3, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to Condensed Consolidated Financial Statements.

3.
Divestitures 
East Texas and Other Properties
In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The carrying value of the net assets disposed in this transaction was $28.5 million, including oil and gas properties and other fixed assets of $32.3 million, net of related asset retirement obligations (“AROs”) of $3.8 million. The net pre-tax operating income (loss) attributable to the East Texas assets was $1.0 million and $(6.9) million for the three months ended September 30, 2015 and 2014 and $1.7 million and $(18.4) million for the nine months ended September 30, 2015 and 2014. The net proceeds from this transactions were used to pay down a portion of our outstanding borrowings under the Revolver.
In October 2015, we also sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for approximately $13 million, net of transaction costs and customary closing adjustments. We expect to recognize a loss of approximately $9 million on this transaction in the fourth quarter of 2015.
Oil Gathering System Construction Rights
In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC (“Republic”) for proceeds of approximately $147 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate transportation

8



services for a substantial portion of our future South Texas crude oil and condensate production. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred to be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be in the first quarter of 2016. In September 2015, the gathering agreement with Republic was amended to reduce the number of wells initially required to be connected to the pipeline system, provide for alternative transportation in areas that will not be served by the pipeline and also reduce the gathering fees. As a result of the amendment, we recognized $8.4 million of deferred gain in September 2015. As of September 30, 2015, $2.3 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $73.5 million, representing the remaining noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.
Natural Gas Gathering and Gas Lift Assets
In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP (“AMID”) for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of our current and future South Texas natural gas production. We realized a gain of $67.3 million, of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period. We amortized $0.3 million of the deferred gain during each of the nine months ended September 30, 2015 and 2014. As of September 30, 2015, $0.4 million of the remaining deferred gain was included as a component of Accounts payable and accrued expenses and $9.5 million, representing the noncurrent portion, was included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

4.       Accounts Receivable and Major Customers
The following table summarizes our accounts receivable by type as of the dates presented:
 
As of
 
September 30,
 
December 31,
 
2015
 
2014
Customers
$
37,010

 
$
62,650

Joint interest partners
29,693

 
120,708

Other
7,872

 
6,549

 
74,575

 
189,907

Less: Allowance for doubtful accounts
(1,555
)
 
(280
)
 
$
73,020

 
$
189,627


For the nine months ended September 30, 2015, two customers accounted for $108.4 million, or approximately 50%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2015 were $62.3 million and $46.1 million, or 29% and 21% of the consolidated total, respectively. As of September 30, 2015, $16.5 million, or approximately 45% of our consolidated accounts receivable from customers, was related to these customers.
For the nine months ended September 30, 2014, four customers accounted for $267.0 million, or approximately 65% of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2014 were $86.2 million, $72.5 million, $55.7 million and $52.6 million, or approximately 21%, 18%, 13% and 13% of the consolidated total. As of December 31, 2014, $39.3 million, or approximately 63% of our consolidated accounts receivable from customers, was related to these customers.
No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

5.
Derivative Instruments
We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility. Our derivative instruments are not formally designated as hedges.
Commodity Derivatives
We 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 oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

9



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 NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.
The following table sets forth our commodity derivative positions as of September 30, 2015:
 
 
 
Average
 
 
 
 
 
 
 
 
 
Volume Per
 
Weighted Average Price
 
Fair Value
 
Instrument
 
Day
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Crude Oil:
 
 
(barrels)
 
($/barrel)
 
 
 
 
Fourth quarter 2015 1
Collars
 
3,000

 
$
86.67

 
$
94.73

 
$
6,817

 
$

Fourth quarter 2015 1
Swaps
 
8,000

 
$
91.06

 
 
 
26,603

 

First quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
17,903

 

Second quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
17,154

 

Third quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
16,764

 

Fourth quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
16,150

 

Settlements to be received in subsequent period
 
 

 
 

 
10,970

 

_______________________
1 Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015.
Financial Statement Impact of Derivatives
The impact of our derivatives activities on income is included in the Derivatives caption on our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Cash settlements and gains (losses):
 
 
 
 
 
 
 
Cash (paid) received for:
 
 
 
 
 
 
 
Commodity contract settlements
$
32,258

 
$
(7,557
)
 
$
104,590

 
$
(17,836
)
Gains (losses) attributable to:
 
 
 
 
 
 
 
Commodity contracts
12,443

 
74,014

 
(52,517
)
 
25,966

 
$
44,701

 
$
66,457

 
$
52,073

 
$
8,130

The effects of derivative gains and (losses) and cash settlements of our commodity derivatives 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 the Net losses (gains) and Cash settlements, net captions.
The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:
 
 
 
Fair Values as of
 
 
 
September 30, 2015
 
December 31, 2014
 
 
 
Derivative
 
Derivative
 
Derivative
 
Derivative
Type
 
Balance Sheet Location
Assets
 
Liabilities
 
Assets
 
Liabilities
Commodity contracts
 
Derivative assets/liabilities – current
$
96,211

 
$

 
$
128,981

 
$

Commodity contracts
 
Derivative assets/liabilities – noncurrent
16,149

 

 
35,897

 

 
 
 
$
112,360

 
$

 
$
164,878

 
$


10



As of September 30, 2015, we reported a commodity derivative asset of $112.4 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with four of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.
6.
Property and Equipment
The following table summarizes our property and equipment as of the dates presented: 
 
As of
 
September 30,
 
December 31,
 
2015
 
2014
Oil and gas properties:
 

 
 

Proved
$
2,687,598

 
$
3,390,482

Unproved
125,571

 
125,676

Total oil and gas properties
2,813,169

 
3,516,158

Other property and equipment
31,423

 
75,073

Total properties and equipment
2,844,592

 
3,591,231

Accumulated depreciation, depletion and amortization
(1,026,006
)
 
(1,766,133
)
 
$
1,818,586

 
$
1,825,098



7.
Long-Term Debt
The following table summarizes our long-term debt as of the dates presented giving effect to the adoption of ASU 2015–03:
 
As of
 
September 30, 2015
 
December 31, 2014
 
Principal
 
Unamortized Issuance Costs
 
Principal
 
Unamortized Issuance Costs
Revolving credit facility 1
$
140,000

 
 
 
$
35,000

 
 
Senior notes due 2019
300,000

 
$
3,510

 
300,000

 
$
4,131

Senior notes due 2020
775,000

 
18,128

 
775,000

 
20,440

Totals
1,215,000

 
$
21,638

 
1,110,000

 
$
24,571

Long-term debt, net of unamortized issuance costs
$
1,193,362

 
 
 
$
1,085,429

 
 
_______________________
1 Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, are presented as a component of Other assets (see Note 10) in accordance with ASU 2015-15.
Revolving Credit Facility
Subsequent to the sale of our East Texas assets in August 2015, the commitment and borrowing base under the Revolver were reduced to $395 million from $425 million. In addition to the outstanding borrowings, we had letters of credit of $1.8 million outstanding as of September 30, 2015. As of September 30, 2015, our available borrowing capacity under the Revolver was $253.2 million.
In November 2015 in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program. The Revolver includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The next semi-annual redetermination is scheduled for May 2016. Revolver borrowings may be used for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.

11



Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, plus, in each case, an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of September 30, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 2.0000%, which is derived from an Adjusted LIBOR rate of 0.2500% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2015, commitment fees were being charged at a rate of 0.375%.
The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries (the “Guarantor Subsidiaries”). The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.
In order to borrow under the Revolver, we must make certain representations and warranties to our bank lenders at the time of each borrowing, including a representation relating to our solvency. If we are unable to make these representations and warranties, we would be unable to borrow under the Revolver, absent a waiver. We will not be able to give the solvency representation if at the time we desire to make a future borrowing we are unable to determine that the fair market value of our assets exceeds the face amount of our liabilities.
The Revolver includes current ratio, leverage ratio and credit exposure financial covenants. Under the current ratio covenant, the ratio of current assets to current liabilities as of the last day of any fiscal quarter may not be less than 1.0 to 1.0. Current assets and current liabilities attributable to derivative instruments are excluded. In addition, current assets include the amount of any unused commitment under the Revolver. Under the leverage ratio covenant, the ratio of total debt to EBITDAX, for any four consecutive quarters may not exceed 4.75 to 1.0 through March 31, 2016; 5.25 to 1.0 through June 30, 2016; 5.50 to 1.0 through December 31, 2016; 4.50 to 1.0 through March 31, 2017; and 4.0 to 1.0 through maturity in September 2017. Furthermore, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if the leverage ratio for the preceding four quarters exceeds 5.0 to 1.0. Under the credit exposure covenant, the ratio of credit exposure to EBITDAX, for any four consecutive quarters ending on or prior to March 31, 2017 may not exceed 2.75 to 1.0. Credit exposure consists of all outstanding borrowings under the Revolver, including any outstanding letters of credit.
2019 Senior Notes
Our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% which is payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in April 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.
2020 Senior Notes
Our 8.50% 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.50% which is payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.
Guarantees
The guarantees under the Revolver and the 2019 Senior Notes and 2020 Senior Notes are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company and its non-guarantor subsidiaries have no material independent assets or operations. There are no significant restrictions on the ability of the parent company to obtain funds from the Guarantor Subsidiaries through dividends, advances or loans.

12



8.
Income Taxes
We recognized a federal income tax benefit for the three and nine months ended September 30, 2015 at the statutory rate of 35%; however, the federal tax benefit 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 recent cumulative losses. The income tax provision includes a benefit of $0.7 million attributable to a federal return to provision adjustment and a minimal deferred state income tax expense of $0.3 million resulting in a combined effective tax rate of 0.4% for the nine months ended September 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.4% is due primarily to the valuation allowance placed against our deferred tax assets.
We recognized an income tax benefit for nine months ended September 30, 2014 at an effective rate of 4.4% which reflects the adverse effects of losses incurred in jurisdictions for which we may not realize a tax benefit and therefore recorded a valuation allowance against the related deferred tax assets.
We paid state income taxes of less than $0.1 million during the nine months ended September 30, 2015 and $0.1 million during the nine months ended September 30, 2014. In October 2015, we received a federal income tax refund of $0.7 million which, as of September 30, 2015, is included as a component of Other current assets on our Condensed Consolidated Balance Sheets.

9.
Firm Transportation Obligation
We have a contractual obligation for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale of our natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production to satisfy this commitment. We recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.
The following table reconciles the obligation as of the dates presented:
 
As of
 
September 30,
 
December 31,
 
2015
 
2014
Balance at beginning of period
$
14,790

 
$
15,993

Accretion
705

 
1,301

Cash payments, net
(1,691
)
 
(2,504
)
Balance at end of period
$
13,804

 
$
14,790

The accretion of the obligation, net of any recoveries from periodic sales of our contractual capacity, is charged as an offset to Other revenue. As of September 30, 2015, $2.8 million of the obligation is classified as current and is included in the Accounts payable and accrued liabilities caption while the remaining $11.0 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.


13



10.
Additional Balance Sheet Detail
The following table summarizes components of selected balance sheet accounts as of the dates presented:
 
As of
 
September 30,
 
December 31,
 
2015
 
2014
Other current assets:
 

 
 

Tubular inventory and well materials
$
2,925

 
$
5,802

Prepaid expenses
3,614

 
4,215

Other
763

 
97

 
$
7,302

 
$
10,114

Other assets:
 

 
 

Assets of supplemental employee retirement plan (“SERP”)
$
4,014

 
$
4,123

Deferred issuance costs of the Revolver
1,796

 
1,623

Other
26

 
95

 
$
5,836

 
$
5,841

Accounts payable and accrued liabilities:
 

 
 

Trade accounts payable
$
24,768

 
$
122,994

Drilling and other lease operating costs
26,643

 
68,842

Royalties and revenue – related
52,062

 
78,359

Compensation – related
12,853

 
9,197

Interest
37,438

 
15,555

Preferred stock dividends

 
6,067

Other
8,144

 
11,213

 
$
161,908

 
$
312,227

Other liabilities:
 

 
 

Deferred gains on sales of assets
$
82,944

 
$
90,569

Firm transportation obligation
11,068

 
12,042

Asset retirement obligations
2,570

 
5,889

Defined benefit pension obligations
1,508

 
1,753

Postretirement health care benefit obligations
965

 
890

Compensation – related
1,150

 
7,631

Deferred compensation – SERP obligations and other
4,020

 
4,183

Other
1,012

 
929

 
$
105,237

 
$
123,886



14



11.
Fair Value Measurements
We apply the authoritative accounting provisions for measuring 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 long-term debt. As of September 30, 2015, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.
The following table summarizes the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for these debt obligations, as of the dates presented:
 
As of
 
September 30, 2015
 
December 31, 2014
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
Senior Notes due 2019
$
68,272

 
$
300,000

 
$
234,000

 
$
300,000

Senior Notes due 2020
197,675

 
775,000

 
620,000

 
775,000

 
$
265,947

 
$
1,075,000

 
$
854,000

 
$
1,075,000

Recurring Fair Value Measurements
Certain financial assets and liabilities are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:
 
 
As of September 30, 2015
 
 
Fair Value
 
Fair Value Measurement Classification
Description
 
Measurement
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 

 
 

 
 

 
 

Commodity derivative assets – current
 
$
96,211

 
$

 
$
96,211

 
$

Commodity derivative assets – noncurrent
 
16,149

 

 
16,149

 

Assets of SERP
 
4,014

 
4,014

 

 

Liabilities:
 
 

 
 

 
 

 
 

Deferred compensation – SERP obligations
 
4,019

 
4,019

 

 

 
 
As of December 31, 2014
 
 
Fair Value
 
Fair Value Measurement Classification
Description
 
Measurement
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 

 
 

 
 

 
 

Commodity derivative assets – current
 
$
128,981

 
$

 
$
128,981

 
$

Commodity derivative assets – noncurrent
 
35,897

 

 
35,897

 

Assets of SERP
 
4,123

 
4,123

 

 

Liabilities:
 
 

 
 

 
 

 
 

Deferred compensation – SERP obligations
 
(4,178
)
 
(4,178
)
 

 

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the nine months ended September 30, 2015 and 2014.

15



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 West Texas Intermediate 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.
Assets of SERP: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.
Deferred compensation SERP obligations: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values are based on quoted market prices, which are level 1 inputs.
Non-Recurring Fair Value Measurements
The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes of recognizing and measuring asset impairments include, but are not limited to, estimates of proved and probable reserves, future commodity prices, 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 are typically not observable, we have categorized the amounts as level 3 inputs.
The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.
12.
Commitments and Contingencies
Drilling and Completion Commitments 
As of September 30, 2015, we had a contractual commitment for one drilling rig with a term expiring in February 2016. The minimum commitment under this agreement is $2.4 million for the fourth quarter of 2015 and $0.8 million in 2016. In September 2015, we renegotiated an existing commitment to purchase certain coil tubing services at a lower rate and extended the expiration from December 31, 2015 to June 30, 2016. The minimum commitment remaining under this agreement is $1.0 million. The drilling rig and coil tubing services agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their scheduled terms. The amount of the penalty is based on the number of days remaining in the contractual term. The penalty amount would have been $3.4 million had we terminated those agreements on September 30, 2015.
In 2015, we reduced our total drilling rig count from eight to one. We incurred a total of $6.2 million in early termination charges with respect to these terminations in the nine months ended September 30, 2015, which have been reported as a component of Exploration expense on our Condensed Consolidated Statements of Operations.
Firm Transportation Commitments
We have entered into contracts for firm transportation capacity rights for specified daily volumes on various pipeline systems with remaining terms that range from less than one to 13 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. The minimum commitment under these agreements is $0.5 million for the fourth quarter of 2015 and approximately $1.1 million per year through 2028. We may sell excess capacity to third parties at our discretion.
Gathering and Intermediate Transportation Commitments
We have a long-term agreement for natural gas gathering, compression and gas lift services for a substantial portion of our natural gas production in the South Texas region through 2038. The agreement requires us to make certain minimum payments regardless of the volume of natural gas production for the first three years of the term. The minimum fee requirement remaining under this agreement is $1.1 million for the fourth quarter of 2015 and $5.0 million in 2016.
We also have long-term agreements for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our payment obligations with respect to these services will begin when construction of the gathering and transportation system is completed, which is expected to be in the first quarter of 2016. The agreements also require us to commit certain minimum volumes of crude oil production for the first ten years of the agreements terms, which will result in minimum fee requirements of approximately $12.3 million on an annual basis.

16



Financial Advisory Commitment
In July 2015, we retained Jefferies to provide financial advice generally and to act as our exclusive financial advisor in connection with asset-level financing transactions with investors related to our Eagle Ford assets, including joint venture arrangement transactions. In connection with this engagement, Jefferies is also advising us with respect to various financing and debt restructuring options. In addition to certain cash-based fees in connection with these services, we have agreed to pay Jefferies an advisory fee of 6.5 million shares of our common stock payable upon the closing of an asset-level financing transaction.
Other Commitments
In connection with our August 2014 acquisition of undeveloped acreage in the Eagle Ford in Lavaca County, Texas, we committed to providing a drilling carry in the amount of $10.7 million to support development of this acreage through July 2017. If we have not incurred the full balance of the drilling carry by the third anniversary date of the transaction, we will be required to make a cash payment to the seller to satisfy any shortfall.
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. During 2010, we established a $0.9 million reserve for a litigation matter that remained outstanding as of September 30, 2015. As of September 30, 2015, we also had AROs of approximately $2.6 million attributable to the plugging of abandoned wells.
 

17



13.
Shareholders’ Equity
The following tables summarize the components of our shareholders equity and the changes therein as of and for the nine months ended September 30, 2015 and 2014:
 
As of
 
 
 
Preferred
 
 
 
 
 
As of
 
December 31,
 
 
 
Stock
 
Dividends
 
All Other
 
September 30,
 
2014
 
Net Loss
 
Offering
 
Declared 1
 
Changes 2
 
2015
Preferred stock 3
$
4,044

 
$

 
$

 
$

 
$
(87
)
 
$
3,957

Common stock 3
529

 

 

 

 
19

 
548

Paid-in capital 3
1,206,305

 

 

 

 
2,882

 
1,209,187

Accumulated deficit
(535,176
)
 
(111,394
)
 

 
(12,134
)
 

 
(658,704
)
Deferred compensation obligation
3,211

 

 

 

 
229

 
3,440

Accumulated other comprehensive income 4
249

 

 

 

 
(32
)
 
217

Treasury stock
(3,345
)
 

 

 

 
(229
)
 
(3,574
)
 
$
675,817

 
$
(111,394
)
 
$

 
$
(12,134
)
 
$
2,782

 
$
555,071

 
 
 
 
 
 
 
 
 
 
 
 
 
As of
 
 
 
Preferred
 
 
 
 
 
As of
 
December 31,
 
 
 
Stock
 
Dividends
 
All Other
 
September 30,
 
2013
 
Net Income
 
Offering
 
Declared 1
 
Changes 2
 
2014
Preferred stock 3
$
1,150

 
$

 
$
3,250

 
$

 
$
(356
)
 
$
4,044

Common stock 3
466

 

 

 

 
62

 
528

Paid-in capital 3
891,351

 

 
310,080

 

 
3,871

 
1,205,302

Accumulated deficit 3
(104,180
)
 
8,102

 

 
(11,081
)
 
(4,256
)
 
(111,415
)
Deferred compensation obligation
2,792

 

 

 

 
314

 
3,106

Accumulated other comprehensive income 4
267

 

 

 

 
74

 
341

Treasury stock
(3,042
)
 

 

 

 
(197
)
 
(3,239
)
 
$
788,804

 
$
8,102

 
$
313,330

 
$
(11,081
)
 
$
(488
)
 
$
1,098,667

_______________________
1 Includes dividends declared of $300.00 per share and $450.00 per share of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the nine months ended September 30, 2015 and 2014, respectively, and $300.00 per share and $198.33 per share of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the nine months ended September 30, 2015 and 2014, respectively.
2 Includes equity-classified share-based compensation of $3,369 and $2,638 for the nine months ended September 30, 2015 and 2014, respectively.
3 A total of 875 shares, or 87,500 depositary shares, of the Series A Preferred Stock were converted into 1,458,336 shares of our common stock during the nine months ended September 30, 2015. A total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5,924,706 shares of our common stock during the nine months ended September 30, 2014. We made payments of $4.3 million to induce the conversion of 3,527 of these shares during the 2014 period.
4 Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the nine months ended September 30, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(49) and $114 and are presented above net of taxes of $(17) and $40, respectively.
In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. While the accumulation does not result in presentation of a liability on the balance sheet, the accumulated dividends are deducted from our net income (or added to our net loss) in the determination of income (loss) attributable to common shareholders and the related earnings (loss) per share. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends, including $1.0 million attributable to dividends of $150.00 per share on 7,070 eligible shares of the Series A Preferred Stock and $4.9 million attributable to dividends of $150.00 per share on 32,500 eligible shares of the Series B Preferred Stock.
If we do not pay dividends on our Series A Preferred Stock and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of both series of preferred stock, voting together as a single class, will have the right to elect two additional directors to serve on our board of directors until all accumulated and unpaid dividends are paid in full.
In May 2015, Penn Virginia’s articles of incorporation were amended to increase the number of total authorized shares of common stock by 100 million to 228 million from 128 million.

18




14.
Share-Based Compensation
The Penn Virginia Corporation 2013 Amended and Restated Long-Term Incentive Plan (the “LTI Plan”) permits the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We recognize compensation expense related to the LTI Plan in the General and administrative caption on our Condensed Consolidated Statements of Operations.
With the exception of performance-based restricted stock units (“PBRSUs”), all of the awards issued under the LTI Plan are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards is measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Accounts payable and accrued liabilities (current portion) and Other liabilities (noncurrent portion) captions on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.
The following table summarizes our share-based compensation expense recognized for the periods presented:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Equity-classified awards:
 
 
 
 
 
 
 
Stock option awards
$
462

 
$
403

 
$
1,242

 
$
1,193

Common, deferred and restricted stock and stock unit awards
801

 
584

 
2,127

 
1,445

 
1,263

 
987

 
3,369

 
2,638

Liability-classified awards
(851
)
 
(360
)
 
(686
)
 
6,632

 
$
412

 
$
627

 
$
2,683

 
$
9,270


In February 2015, we paid $1.5 million in cash pursuant to the terms of PBRSU grants made in 2012.

15.
Interest Expense
 
The following table summarizes the components of interest expense for the periods presented:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Interest on borrowings and related fees
$
23,239

 
$
22,559

 
$
69,371

 
$
69,477

Amortization of debt issuance costs
1,224

 
1,063

 
3,504

 
3,114

Capitalized interest
(1,478
)
 
(1,669
)
 
(4,854
)
 
(4,875
)
 
$
22,985

 
$
21,953

 
$
68,021

 
$
67,716




19




16.
Earnings per Share
 
The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss)
$
25,900

 
$
89,661

 
$
(111,394
)
 
$
8,102

Less: Preferred stock dividends
(5,935
)
 
(7,641
)
 
(18,069
)
 
(11,081
)
Less: Induced conversion of preferred stock

 
(888
)
 

 
(4,256
)
Net income (loss) attributable to common shareholders – basic
$
19,965

 
$
81,132

 
$
(129,463
)
 
$
(7,235
)
Add: Preferred stock dividends 1
5,935

 
7,641

 

 

Add: Induced conversion of preferred stock 1

 
888

 

 

Net income (loss) attributable to common shareholders – diluted
$
25,900

 
$
89,661

 
$
(129,463
)
 
$
(7,235
)
 
 
 
 
 
 
 
 
Weighted-average shares – basic
72,651

 
71,536

 
72,438

 
67,909

Effect of dilutive securities 2
30,801

 
32,070

 

 

Weighted-average shares – diluted
103,452

 
103,606

 
72,438

 
67,909

_______________________
1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.
2 For the nine months ended September 30, 2015 and 2014, approximately 31.1 million and 24.9 million, respectively, of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

20



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: 
the volatility of commodity prices for oil, natural gas liquids, or NGLs and natural gas;
our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;
compliance with debt covenants;
reductions in the borrowing base under our revolving credit facility, or the Revolver;
our ability to continue to borrow under the Revolver;
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, 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 the 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 natural gas reserves;
drilling and operating risks;
our ability to compete effectively against other oil and gas companies;
our ability to successfully monetize select assets and repay our debt;
leasehold terms expiring before production can be established;
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 force majeure events;
our ability to retain or attract senior management and key technical 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; 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, 2014 and Item 1A of Part II of this Quarterly Report on Form 10-Q.
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.

21



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 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 Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. 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, NGLs and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have less significant operations in Oklahoma, primarily the Granite Wash. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 million barrels of oil equivalent, or MMBOE, including approximately 15.8 MMBOE of proved reserves attributable to our recently divested East Texas assets in August 2015 and certain non-core properties in South Texas that were sold in October 2015.
The following table sets forth certain summary operating and financial statistics for the periods presented: 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Total production (MBOE)
1,930

 
2,089

 
6,295

 
5,973

Average daily production (BOEPD)
20,976

 
22,706

 
23,058

 
21,881

Crude oil and NGL production (MBbl)
1,537

 
1,555

 
4,934

 
4,238

Crude oil and NGL production as a percent of total
80
%
 
74
%
 
78
%
 
71
%
Product revenues, as reported
$
60,690

 
$
141,860

 
$
216,948

 
$
411,441

Product revenues, as adjusted for derivatives
$
92,948

 
$
134,303

 
$
321,538

 
$
393,605

Crude oil and NGL revenues as a percent of total, as reported
90
%
 
91
%
 
90
%
 
88
%
Realized prices:
 
 
 
 
 
 
 
Crude oil ($/Bbl)
$
42.42

 
$
95.19

 
$
47.35

 
$
97.72

NGL ($/Bbl)
$
9.81

 
$
31.76

 
$
12.45

 
$
34.18

Natural gas ($/Mcf)
$
2.68

 
$
4.17

 
$
2.71

 
$
4.60

Aggregate ($/BOE)
$
31.45

 
$
67.91

 
$
34.46

 
$
68.88

Operating costs ($/BOE):
 
 
 
 
 
 
 
Lease operating
$
5.86

 
$
7.07

 
$
5.37

 
$
6.17

Gathering, processing and transportation
2.93

 
2.60

 
3.10

 
2.11

Production and ad valorem taxes
1.80

 
3.68

 
2.09

 
3.77

General and administrative 1
4.67

 
5.22

 
4.79

 
5.66

Total operating costs
$
15.26

 
$
18.57

 
$
15.35

 
$
17.71

Depreciation, depletion and amortization ($/BOE)
$
39.82

 
$
34.47

 
$
40.20

 
$
36.10

Cash provided by operating activities
$
63,960

 
$
101,257

 
$
162,241

 
$
200,450

Cash paid for capital expenditures
$
60,883

 
$
194,451

 
$
324,876

 
$
545,031

Cash and cash equivalents at end of period
 
 
 
 
$
3,342

 
$
123,690

Debt outstanding at end of period
 
 
 
 
$
1,215,000

 
$
1,075,000

Credit available under revolving credit facility at end of period 2
 
 
 
 
$
253,196

 
$
453,846

Net development wells drilled and completed
6.5

 
15.4

 
34.1

 
44.2

_______________________
1 Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.65 and $0.47 for the three months ended September 30, 2015 and 2014 and $0.54 and $0.44 for the nine months ended September 30, 2015 and 2014 and liability-classified share-based compensation of $(0.44) and $(0.17) for the three months ended September 30, 2015 and 2014 and $(0.11) and $1.11 for the nine months ended September 30, 2015 and 2014.
2 Based on the commitment and borrowing base of $395 million as of September 30, 2015 less outstanding borrowings and letters of credit.


22



As discussed in greater detail in the “Key Developments” and “Financial Condition” sections that follow, due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:
We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period. We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.
We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015.
We suspended the payment of dividends on our convertible preferred stock in September 2015.
We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015.
We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.
We engaged Jefferies LLC, or Jefferies, to advise us with respect to asset-level financing transactions and various financing and debt restructuring options.
To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The “Financial Condition – Capital Resources” discussion that follows and Note 5 to the Condensed Consolidated Financial Statements provides a detailed summary of our open commodity derivative positions as well as the historical results of our hedging program for the three and nine months ended September 30, 2015 and 2014.
In the three months ended September 30, 2015, our crude oil and NGL production increased to 80 percent from 74 percent of our total production compared to the three month period ended September 30, 2014. Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. As of November 6, 2015, we operated approximately 300 producing Eagle Ford wells and had working interests in an additional 36 non-operated producing Eagle Ford wells. Through this date, we have accumulated approximately 100,000 net acres in the Eagle Ford. We are currently operating one drilling rig in the Eagle Ford. Our 2015 capital program, which is exclusively dedicated to this play, is being financed with a combination of cash from operating activities, proceeds from the sale of non-core assets and borrowings under the Revolver.

Key Developments
The following general business developments and corporate actions had or may have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) decreases to the commitment and borrowing base under the Revolver, (ii) ongoing efforts to refinance the Company and improve liquidity, (iii) depressed commodity prices and our hedging program, (iv) the suspension of dividends on our our Series A 6% Convertible Perpetual Preferred Stock, or Series A Preferred Stock, and our Series B 6% Convertible Perpetual Preferred Stock, or Series B Preferred Stock, (v) production, development and capital expenditures in the Eagle Ford and (vi) the sale of our East Texas and other assets.
Revolver Commitment and Borrowing Base Reduction
In November 2015 in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program (see Note 7 to the Condensed Consolidated Financial Statements and the “Financial Condition” discussion that follows).
Ongoing Efforts to Refinance the Company
In July 2015, we retained Jefferies to provide financial advice generally and to act as our exclusive financial advisor in connection with asset-level financing transactions with investors related to our Eagle Ford assets, including joint venture arrangement transactions. In connection with this engagement, Jefferies is advising us with respect to various financing and debt restructuring options. In addition to certain cash-based fees in connection with these services, we have agreed to pay Jefferies an advisory fee of 6.5 million shares of our common stock payable upon the closing of an asset-level financing transaction.

23



Depressed Commodity Prices and Our Hedging Program
Commodity prices continued to be volatile and depressed during the first three quarters of 2015. Our crude oil derivatives supported our liquidity by providing cash settlements of $32.3 million and $103.9 million during the three and nine months ended September 30, 2015. We have hedged approximately 11,000 barrels of oil per day, or BOPD, or approximately 95 percent of our expected crude oil production for the remainder of 2015, at a weighted-average floor/swap price of $89.86 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the remainder of 2015. No volumes are subject to the put options in 2016. For 2016, we have hedged a total of approximately 6,000 BOPD at a weighted-average swap price of $80.41 per barrel. We expect to remain unhedged with respect to natural gas production for the foreseeable future.
Suspension of Preferred Stock Dividends
In September 2015, we announced a suspension of quarterly dividends on our outstanding Series A and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends. We will re-evaluate the dividend payment policy on a quarterly basis.
The suspension of quarterly dividends does not affect our business operations and does not cause an event of default under any of our debt agreements.
If we do not pay dividends on our Series A and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of both series of preferred stock, voting together as a single class, will have the right to elect two additional directors to serve on our board of directors until all accumulated and unpaid dividends are paid in full.
Production, Development and Capital Expenditures in the Eagle Ford
Our Eagle Ford production was 18,528 BOEPD during the three months ended September 30, 2015 with oil comprising 12,826 BOPD, or 69 percent, and NGLs and natural gas comprising approximately 17 percent and 14 percent. Our third quarter production represented a nine percent decrease compared to 20,259 BOEPD during the three months ended June 30, 2015, of which 13,750 BOPD, or 68 percent, was crude oil, 17 percent was NGLs and 15 percent was natural gas. The sequential decline in production was attributable primarily to our reduction in drilling activity as the year progressed in light of lower oil and gas prices.
During the three months ended September 30, 2015, we drilled and completed nine gross (6.5 net) wells in the Eagle Ford for a total of 55 gross (34.1 net) wells on a year-to-date basis. The average drilling and completion costs for 11 gross (two-string) wells turned in line during the three months ended September 30, 2015 was approximately $5.7 million, or 30 percent lower from an average of $8.2 million for 16 gross (two-string and three-string wells) wells turned in line in the three months ended June 30, 2015. The decrease in average drilling and completion cost was driven by a transition to drilling exclusively two-string wells, whereas only three of the second quarter wells were two-string wells. In addition, seven of the third quarter wells were slickwater stimulated and all of the third quarter wells were fractured with approximately 46 percent more proppant per stage, on average, than second quarter wells.
During the three months ended September 30, 2015, we have turned in line 11 gross (8.5 net) operated wells. As a group, these 11 wells had an average IP rate of 1,501 BOEPD over an average of 21.2 frac stages, with 93 percent of production from crude oil, compared to 798 BOEPD over an average of 24.4 frac stages for 16 wells in the three months ended June 30, 2015. All of the third quarter wells were drilled in the Lower Eagle Ford and had a 30-day average rate of 790 BOEPD, with 92 percent of production from crude oil, compared to an average of 497 BOEPD for the second quarter wells. The average amount of proppant per stage for these 11 wells was approximately 422,000 pounds and the average amount of proppant per lateral foot was approximately 1,800 pounds, compared to approximately 290,000 pounds per stage and 1,170 pounds per lateral foot in the three months ended June 30, 2015. We believe the strong improvement in early-time production rates is attributable to the use of slickwater stimulations, continued use of “zipper fracs” for alternating laterals on multi-well pads and increased frac intensity as measured by the increased proppant pumped per stage.
We anticipate total capital expenditures in 2015 of up to approximately $324 million including up to approximately $43 million during the fourth quarter of 2015. Preliminarily, we estimate 2016 capital expenditures to be up to approximately $160 million. For the remainder of 2015 and for 2016, due primarily to anticipated low oil prices, we will continue to focus our efforts on drilling, using one rig, less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where our economics are optimized.

24



Sale of East Texas and Other Assets
In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The properties sold had net production of 1,898 BOEPD during the second quarter of 2015, consisting of 74 percent natural gas, 19 percent NGLs and seven percent crude oil. As a result of the divestiture, reported 2015 production is expected to decrease by an estimated 200 MBOE. Estimated proved reserves associated with the properties as of December 31, 2014 were 13.7 MMBOE, 85 percent of which were proved developed. The reserves consisted of 77 percent natural gas, 16 percent NGLs and six percent crude oil. The net proceeds from this transactions were used to pay down a portion of our outstanding borrowings under the Revolver.
In October 2015, we also sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for approximately $13 million, net of transaction costs and customary closing adjustments. We expect to recognize a loss of approximately $9 million on this transaction in the fourth quarter of 2015.


25



Financial Condition
Liquidity
Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our 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.
During 2015, our capital expenditures will exceed our projected cash from operating activities; however, we have no debt maturities until September 2017 when the Revolver matures. We expect that we will be able to fund our capital expenditures as well as meet our debt service requirements and meet our working capital requirements for the remainder of 2015 with cash from operating activities, borrowings under the Revolver and proceeds from the sale of non-core assets.
In November 2015, in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver from $395 million to $275 million. Based on our current borrowings of $170 million and outstanding letters of credit of $1.8 million, we have only $103.2 million of borrowing capacity available under the Revolver as of November 6, 2015. While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior notes become due in April and May of 2016. Unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016. Moreover, the borrowing base under the Revolver may be further reduced in connection with the next semi-annual redetermination in May 2016. Such a further reduction could prevent us from borrowing additional amounts under the Revolver or, if the borrowing base were to be reduced below the then-outstanding borrowings, could require us to repay the shortfall.
Using prices through September 30, 2015, we estimate that our proved reserve volumes and the present value (discounted at 10% per annum) of estimated future net revenues of our proved oil and gas reserves, or PV10, has declined from the year-end 2014 estimates due primarily to the continued decline in commodity prices and reductions in our projected development plans, partially offset by lower estimated drilling costs and other direct expenses. We estimate that our proved reserves were 68.6 MMBOE and our PV10 was approximately $614 million as of September 30, 2015 as compared to 114.8 MMBOE and $1,472 million as of December 31, 2014, respectively. The decline in our PV10 could lead to further reductions in the borrowing base under the Revolver and could otherwise limit our ability to obtain alternative financing. Our cash flows, operating results, future growth prospects and financial condition, as well as our proved reserves volumes and PV10, could continue to be negatively impacted if the currently depressed crude oil and natural gas prices persist or deteriorate further.
Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection. Collectively, the factors discussed above raise substantial doubt about our ability to continue as a going concern.
Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing, and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.
Capital Resources
In 2015, we anticipate making capital expenditures of up to approximately $324 million in the aggregate including up to $43 million in the fourth quarter. We expect to allocate substantially all of our capital expenditures to the Eagle Ford. This includes approximately 93 percent for drilling and completions, five percent for leasehold acquisition and two percent for facilities and other projects. Our business plan for the remainder of 2015 assumes a drilling program utilizing one operated drilling rig. We continually review our drilling and capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, product pricing, industry conditions, cash from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the Cash Flows discussion that follows.

26



Cash From Operating Activities. In addition to commodity price volatility, as discussed in detail below, our cash from operating activities is impacted by the timing of our working capital requirements. The most significant component thereof is attributable to the timing of payments made for drilling and completion capital expenditures and the related billing and collection of amounts from our partners. 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 our related working capital burden.
We actively manage the exposure of our revenues to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar and swap contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices, the magnitude of our capital program and our operating strategy. During the nine months ended September 30, 2015, our commodity derivatives portfolio resulted in $103.9 million and $0.7 million of net cash receipts related to lower than anticipated prices received for our crude oil and natural gas production, respectively. If commodity prices remain depressed, we anticipate that our derivative portfolio will continue to result in receipts from settlements during the fourth quarter of 2015.
We have hedged approximately 11,000 BOPD, or approximately 95 percent of our expected crude oil production during the remainder of 2015, at a weighted-average floor/swap price of $89.86 per barrel. For 2016, we have hedged approximately 6,000 BOPD at weighted-average swap price of $80.41 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015. Our natural gas hedges have expired and we anticipate remaining unhedged with respect to natural gas production for the remainder of 2015.
Revolver Borrowings. The Revolver provides for a revolving commitment and borrowing base which is currently $275 million. The Revolver includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The next semi-annual redetermination is scheduled for May 2016. Revolver borrowings may be used for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.
Subsequent to the sale of our East Texas assets in August 2015, the commitment and borrowing base under the Revolver were reduced to $395 million from $425 million. In addition to the outstanding borrowings, we had letters of credit of $1.8 million outstanding as of September 30, 2015. As of September 30, 2015, our available borrowing capacity under the Revolver was $253.2 million.
The following table summarizes our borrowing activity under the Revolver during the periods presented
 
Borrowings Outstanding
 
 
 
Weighted-
Average
 
Maximum
 
Weighted-
Average Rate
Three months ended September 30, 2015
$
191,065

 
$
218,000

 
2.2325
%
Nine months ended September 30, 2015
$
178,407

 
$
232,000

 
2.1036
%
In order to borrow under the Revolver, we must make certain representations and warranties to our bank lenders at the time of each borrowing, including a representation relating to our solvency. If we are unable to make these representations and warranties, we would be unable to borrow under the Revolver, absent a waiver. We will not be able to give the solvency representation if at the time we desire to make a future borrowing we are unable to determine that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty as to our ability to continue to give the required representation regarding solvency. If we are unable to give the required representation, then we will need a waiver from our bank lenders in order to continue to be able to borrow under the Revolver. Although we believe our bank lenders’ loans are well secured under the terms of the Revolver, there is no assurance that the bank lenders will waive the requirement to give all representations and warranties.
Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-core undeveloped acreage, among others.
Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we consider capital market transactions, including the offering of debt and equity securities. Historically, we have entered into such transactions to facilitate acquisitions and to pursue opportunities to adjust our total capitalization.

27



Cash Flows
The following table summarizes our cash flows for the periods presented:
 
Nine Months Ended
 
 
 
September 30,
 
 
 
2015
 
2014
 
Variance
Cash flows from operating activities
 
 
 
 


Operating cash flows, net
$
125,248

 
$
300,644

 
$
(175,396
)
Working capital changes (excluding interest, income taxes and restructuring costs paid), net
(14,797
)
 
(35,740
)
 
20,943

Commodity derivative settlements received (paid), net:
 
 
 
 


Crude oil
103,909

 
(15,987
)
 
119,896

Natural gas
681

 
(1,849
)
 
2,530

Interest payments, net of amounts capitalized
(42,635
)
 
(42,903
)
 
268

Income taxes paid
(7
)
 
(100
)
 
93

Drilling rig termination charges paid
(6,416
)
 

 
(6,416
)
Strategic and financial advisory costs paid
(1,195
)
 

 
(1,195
)
ERP system development costs paid

 
(1,045
)
 
1,045

Acquisition arbitration and other costs paid

 
(589
)
 
589

Restructuring and exit costs paid
(2,547
)
 
(1,981
)
 
(566
)
Net cash provided by operating activities
162,241

 
200,450

 
(38,209
)
Cash flows from investing activities
 

 
 

 
 

Receipts to settle working capital adjustments assumed in acquisition, net

 
33,712

 
(33,712
)
Capital expenditures – property and equipment
(324,876
)
 
(545,031
)
 
220,155

Proceeds from sales of assets, net
73,670

 
311,913

 
(238,243
)
Net cash used in investing activities
(251,206
)
 
(199,406
)
 
(51,800
)
Cash flows from financing activities
 

 
 

 
 

Proceeds from the issuance of preferred stock, net

 
313,330

 
(313,330
)
Payments made to induce conversion of preferred stock

 
(4,256
)
 
4,256

Proceeds (repayments) from revolving credit facility borrowings, net
105,000

 
(206,000
)
 
311,000

Debt issuance costs paid
(744
)
 
(151
)
 
(593
)
Dividends paid on preferred stock
(18,201
)
 
(5,165
)
 
(13,036
)
Other, net

 
1,414

 
(1,414
)
Net cash provided by financing activities
86,055

 
99,172

 
(13,117
)
Net (decrease) increase in cash and cash equivalents
$
(2,910
)
 
$
100,216

 
$
(103,126
)
Cash Flows From Operating Activities. Despite higher total production volume during the nine months ended September 30, 2015 compared to the corresponding period in 2014, commodity prices declined substantially resulting in lower realized cash receipts from product sales. During the 2015 period, we paid early termination charges for the release of four drilling rigs, of which $0.7 million was accrued at the end of 2014. During the 2015 period, we also incurred and paid professional fees and other consulting costs associated with our ongoing initiatives with respect to corporate strategy, including the search for a new chief executive officer, and refinancing the Company. Restructuring and exit costs were higher during the 2015 period due primarily to the payment of termination and severance benefits of $0.8 million in connection with ongoing efforts to reduce our our administrative cost structure. The overall decline in operating cash flows was partially offset by a combination of (i) cash settlements from our commodity derivatives portfolio which generated cash receipts during the 2015 period as compared to net payments during the 2014 period, (ii) lower working capital changes driven by the timing of net collections from joint venture partners during the 2015 period as our capital program contracted as compared to the 2014 period when the capital program was expanding and (iii) non-recurring payments for ERP system development costs and acquisition-related arbitration and other costs paid in the 2014 period.

28



Cash Flows From Investing Activities. Cash paid for capital expenditures was substantially lower during the nine months ended September 30, 2015 compared to the corresponding period during 2014 due primarily to the reduction in our capital program including reductions in the number of operating drilling rigs and well completion and frac crews. Our capital expenditures during the 2015 period were partially offset by the receipt of net proceeds from the sale of our East Texas assets. Capital expenditures during the 2014 period were partially offset by the receipt of net proceeds from the sale of our natural gas gathering and gas lift assets in South Texas in January 2014, the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas in July 2014, the sale of our Selma Chalk assets in Mississippi in July 2014 and proceeds from the resolution of arbitration matters in connection with a 2013 acquisition.
The following table sets forth costs related to our capital program for the periods presented:
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Oil and gas:
 

 
 

Drilling and completion
$
262,130

 
$
438,150

Lease acquisitions and other land-related costs 1
13,587

 
99,917

Pipeline, gathering facilities and other equipment
3,634

 
11,811

Geological, geophysical (seismic) and delay rental costs
836

 
5,608

 
280,187

 
555,486

Other – Corporate
526

 
1,287

Total capital program costs
$
280,713

 
$
556,773

______________________
1 Includes site preparation and other pre-drilling costs.
The following table reconciles the total costs of our capital program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Total capital program costs
$
280,713

 
$
556,773

Decrease (increase) in accrued capitalized costs
41,800

 
(12,805
)
Less:
 
 
 
Exploration costs charged to operations:
 
 
 
Geological, geophysical (seismic) and delay rental costs
(836
)
 
(5,608
)
Transfers from tubular inventory and well materials
(4,154
)
 
(35
)
Add:
 

 
 

Tubular inventory and well materials purchased in advance of drilling
2,499

 
1,831

Capitalized interest
4,854

 
4,875

Total cash paid for capital expenditures
$
324,876

 
$
545,031

Cash Flows From Financing Activities. Cash flows from financing activities for the nine months ended September 30, 2015 included net borrowings of $105 million under the Revolver used to fund a portion of our capital expenditures while the 2014 period included net repayments of $206 million sourced primarily by the offering of our Series B Preferred Stock, the net proceeds from the sale of our South Texas natural gas gathering and gas lift assets, the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas and the sale of our Selma Chalk assets in Mississippi. We paid total dividends of $18.2 million for the Series A Preferred Stock and Series B Preferred Stock during the nine months ended September 30, 2015. Dividends of $5.2 million were paid during the comparable period in 2014 on the Series A Preferred Stock as well as $4.3 million of payments to induce the conversion of approximately 30 percent of the outstanding shares of the Series A Preferred Stock. We paid issuance costs associated with amendments to the Revolver during both the 2015 and 2014 periods including $0.7 million in the 2015 period and $0.2 million in the 2014 period. We also received proceeds of $1.4 million during the 2014 period from the exercise of stock options.

29



Capitalization
The following table summarizes our total capitalization as of the dates presented:
 
September 30,
 
December 31,
 
2015
 
2014
Revolving credit facility
$
140,000

 
$
35,000

Senior notes due 2019
300,000

 
300,000

Senior notes due 2020
775,000

 
775,000

Total debt
1,215,000

 
1,110,000

Shareholders’ equity 1
555,071

 
675,817

 
$
1,770,071

 
$