Attached files

file filename
EX-31.2 - EXHIBIT 31.2 - PENN VIRGINIA CORPpva-20150630xex312.htm
EX-12.1 - EXHIBIT 12.1 - PENN VIRGINIA CORPpva-20150630xex121.htm
EX-32.2 - EXHIBIT 32.2 - PENN VIRGINIA CORPpva-20150630xex322.htm
EX-32.1 - EXHIBIT 32.1 - PENN VIRGINIA CORPpva-20150630xex321.htm
EX-31.1 - EXHIBIT 31.1 - PENN VIRGINIA CORPpva-20150630xex311.htm


 
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 June 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 July 24, 2015, 71,676,606 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 June 30, 2015
 Table of Contents
Part I - Financial Information
Item
 
Page
1.
Financial Statements:
 
 
Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2015 and 2014
 
Condensed Consolidated Statements of Comprehensive Income for the Periods Ended June 30, 2015 and 2014
 
Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014
 
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 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
 
Results of Operations
 
Financial Condition
 
Critical Accounting Estimates
3.
Quantitative and Qualitative Disclosures About Market Risk
4.
Controls and Procedures
Part II - Other Information
1.
Legal Proceedings
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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Revenues
 
 
 
 
 
 
 
Crude oil
$
70,672

 
$
112,090

 
$
129,840

 
$
217,666

Natural gas liquids (NGLs)
5,191

 
8,037

 
10,587

 
17,410

Natural gas
7,260

 
16,302

 
15,831

 
34,505

Gain (loss) on sales of property and equipment, net
66

 
(51
)
 
(25
)
 
56,775

Other, net
427

 
2,983

 
1,910

 
2,870

Total revenues
83,616

 
139,361

 
158,143

 
329,226

Operating expenses
 
 
 
 
 
 
 
Lease operating
10,907

 
12,001

 
22,476

 
22,117

Gathering, processing and transportation
6,383

 
3,928

 
13,881

 
7,177

Production and ad valorem taxes
4,967

 
7,510

 
9,656

 
14,815

General and administrative
11,479

 
14,840

 
23,449

 
31,528

Exploration
4,362

 
3,373

 
10,249

 
12,009

Depreciation, depletion and amortization
85,416

 
71,437

 
176,206

 
143,624

Impairments
1,084

 
117,908

 
1,084

 
117,908

Total operating expenses
124,598

 
230,997

 
257,001

 
349,178

Operating loss
(40,982
)
 
(91,636
)
 
(98,858
)
 
(19,952
)
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(23,023
)
 
(23,229
)
 
(45,036
)
 
(45,763
)
Derivatives
(15,495
)
 
(42,665
)
 
7,372

 
(58,327
)
Other
(540
)
 
30

 
(542
)
 
31

Loss before income taxes
(80,040
)
 
(157,500
)
 
(137,064
)
 
(124,011
)
Income tax (expense) benefit
(89
)
 
56,716

 
(230
)
 
42,452

Net loss
(80,129
)
 
(100,784
)
 
(137,294
)
 
(81,559
)
Preferred stock dividends
(6,067
)
 
(1,718
)
 
(12,134
)
 
(3,440
)
Induced conversion of preferred stock

 
(3,368
)
 

 
(3,368
)
Net loss attributable to common shareholders
$
(86,196
)
 
$
(105,870
)
 
$
(149,428
)
 
$
(88,367
)
Net loss per share:
 
 
 
 
 
 
 
Basic
$
(1.19
)
 
$
(1.59
)
 
$
(2.07
)
 
$
(1.34
)
Diluted
$
(1.19
)
 
$
(1.59
)
 
$
(2.07
)
 
$
(1.34
)
 
 
 
 
 
 
 
 
Weighted average shares outstanding – basic
72,398

 
66,514

 
72,330

 
66,065

Weighted average shares outstanding – diluted
72,398

 
66,514

 
72,330

 
66,065


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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Net loss
$
(80,129
)
 
$
(100,784
)
 
$
(137,294
)
 
$
(81,559
)
Other comprehensive income (loss):
 

 
 

 
 
 
 
Change in pension and postretirement obligations, net of tax of $(5) and $(11) in 2015 and $13 and $26 in 2014
(10
)
 
24

 
(21
)
 
49

 
(10
)
 
24

 
(21
)
 
49

Comprehensive loss
$
(80,139
)
 
$
(100,760
)
 
$
(137,315
)
 
$
(81,510
)
 
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
 
June 30,
 
December 31,
 
2015
 
2014
Assets
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
4,441

 
$
6,252

Accounts receivable, net of allowance for doubtful accounts
104,636

 
189,627

Derivative assets
80,372

 
128,981

Deferred income taxes

 
53

Other current assets
8,381

 
10,114

Total current assets
197,830

 
335,027

Property and equipment, net (successful efforts method)
1,888,892

 
1,825,098

Derivative assets
19,546

 
35,897

Other assets
6,322

 
5,841

Total assets
$
2,112,590

 
$
2,201,863

 
 
 
 
Liabilities and Shareholders’ Equity
 

 
 

Current liabilities
 

 
 

Accounts payable and accrued liabilities
$
197,889

 
$
312,227

Derivative liabilities

 

Total current liabilities
197,889

 
312,227

Other liabilities
117,582

 
123,886

Deferred income taxes
4,838

 
4,504

Long-term debt, net of unamortized issuance costs
1,264,363

 
1,085,429

 
 
 
 
Commitments and contingencies (Note 12)


 


 
 
 
 
Shareholders’ equity:
 

 
 

Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,945 shares issued as of June 30, 2015 and December 31, 2014 and Series B – 32,500 shares issued as of June 30, 2015 and December 31, 2014, each with a redemption value of $10,000 per share
4,044

 
4,044

Common stock of $0.01 par value – 228,000,000 shares authorized; 71,676,606 and 71,568,936 shares issued as of June 30, 2015 and December 31, 2014, respectively
530

 
529

Paid-in capital
1,207,854

 
1,206,305

Accumulated deficit
(684,604
)
 
(535,176
)
Deferred compensation obligation
3,354

 
3,211

Accumulated other comprehensive income
228

 
249

Treasury stock – 293,426 and 262,070 shares of common stock, at cost, as of June 30, 2015 and December 31, 2014, respectively
(3,488
)
 
(3,345
)
Total shareholders’ equity
527,918

 
675,817

Total liabilities and shareholders’ equity
$
2,112,590

 
$
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)
 
Six Months Ended
 
June 30,
 
2015
 
2014
Cash flows from operating activities
 

 
 

Net loss
$
(137,294
)
 
$
(81,559
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
176,206

 
143,624

Impairments
1,084

 
117,908

Accretion of firm transportation obligation
445

 
584

Derivative contracts:
 
 
 
Net (gains) losses
(7,372
)
 
58,327

Cash settlements, net
72,332

 
(10,279
)
Deferred income tax expense (benefit)
230

 
(42,452
)
Loss (gain) on sales of assets, net
25

 
(56,775
)
Non-cash exploration expense
4,005

 
6,579

Non-cash interest expense
2,280

 
2,051

Share-based compensation (equity-classified)
2,106

 
1,651

Other, net
3

 
281

Changes in operating assets and liabilities, net
(15,769
)
 
(40,747
)
Net cash provided by operating activities
98,281

 
99,193

 
 
 
 
Cash flows from investing activities
 

 
 

Capital expenditures – property and equipment
(263,993
)
 
(350,580
)
Proceeds from sales of assets, net
(221
)
 
96,632

Net cash used in investing activities
(264,214
)
 
(253,948
)
 
 
 
 
Cash flows from financing activities
 

 
 

Proceeds from the issuance of preferred stock, net

 
313,646

Payments made to induce conversion of preferred stock

 
(3,368
)
Proceeds from revolving credit facility borrowings
197,000

 
302,000

Repayment of revolving credit facility borrowings
(20,000
)
 
(453,000
)
Debt issuance costs paid
(744
)
 
(151
)
Dividends paid on preferred stock
(12,134
)
 
(3,836
)
Other, net

 
1,085

Net cash provided by financing activities
164,122

 
156,376

Net (decrease) increase in cash and cash equivalents
(1,811
)
 
1,621

Cash and cash equivalents – beginning of period
6,252

 
23,474

Cash and cash equivalents – end of period
$
4,441

 
$
25,095

 
 
 
 
Supplemental disclosures:
 

 
 

Cash paid for:
 

 
 

Interest
$
46,041

 
$
47,034

Income taxes
$
7

 
$
100

Non-cash investing activities:
 
 
 
Changes in accrued liabilities related to capital expenditures
$
(20,570
)
 
$
(858
)
 
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 June 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 operations in the Oklahoma, primarily the Granite Wash, and the Haynesville Shale and Cotton Valley in East Texas.

2.
Basis of Presentation
Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“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 six months ended June 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 period have been reclassified to conform to the current year presentation.
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 our revolving credit facility (the “Revolver”) continue to be presented, net of amortization, as a component of Other assets (see Note 10).
In May 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, currently anticipated on January 1, 2018. 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.
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 pending sale of our East Texas assets (see 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 
In July 2015, we entered into an agreement to sell our East Texas assets for gross cash proceeds of $75 million. The sale is expected to close by the end of August 2015 and is subject to customary purchase price adjustments and other customary closing conditions. The effective date of the sale is May 1, 2015.
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 $0.2 million of the deferred gain during each of the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $9.6 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

7



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 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 and will be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be in the fourth quarter of 2015. As of June 30, 2015, $2.6 million of the deferred gain is included as a component of Accounts payable and accrued expenses and $81.5 million, representing the noncurrent portion, is 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
 
June 30,
 
December 31,
 
2015
 
2014
Customers
$
59,906

 
$
62,650

Joint interest partners
39,412

 
120,708

Other
5,873

 
6,549

 
105,191

 
189,907

Less: Allowance for doubtful accounts
(555
)
 
(280
)
 
$
104,636

 
$
189,627


For the six months ended June 30, 2015, three customers accounted for $96.7 million, or approximately 62%, of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2015 were $41.2 million, $36.1 million and $19.4 million, or 26%, 23% and 13% of the consolidated total, respectively. As of June 30, 2015, $30.2 million, or approximately 50% of our consolidated accounts receivable from customers was related to these customers. For the six months ended June 30, 2014, four customers accounted for $148.8 million, or approximately 55% of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2014 were $48.4 million, $35.5 million, $34.0 million and $30.9 million, or approximately 18%, 13%, 13% and 11% of the consolidated total, respectively. As of December 31, 2014, $36.1 million, or approximately 58% 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.
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.

8



The following table sets forth our commodity derivative positions as of June 30, 2015:
 
 
 
Average
 
 
 
 
 
 
 
 
 
Volume Per
 
Weighted Average Price
 
Fair Value
 
Instrument
 
Day
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Crude Oil:
 
 
(barrels)
 
($/barrel)
 
 
 
 
Third quarter 2015 1
Collars
 
3,000

 
$
86.67

 
$
94.73

 
$
5,484

 
$

Fourth quarter 2015 1
Collars
 
3,000

 
$
86.67

 
$
94.73

 
5,186

 

Third quarter 2015 1
Swaps
 
8,000

 
$
91.06

 
 
 
20,056

 

Fourth quarter 2015 1
Swaps
 
8,000

 
$
91.06

 
 
 
19,238

 

First quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
10,273

 

Second quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
10,011

 

Third quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
9,911

 

Fourth quarter 2016
Swaps
 
6,000

 
$
80.41

 
 
 
9,635

 

Settlements to be received in subsequent period
 
 

 
 

 
10,125

 

_______________________
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 third and fourth quarters 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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Cash settlements and gains (losses):
 
 
 
 
 
 
 
Cash (paid) received for:
 
 
 
 
 
 
 
Commodity contract settlements
$
34,840

 
$
(7,222
)
 
$
72,332

 
$
(10,279
)
Losses attributable to:
 
 
 
 
 
 
 
Commodity contracts
(50,335
)
 
(35,443
)
 
(64,960
)
 
(48,048
)
 
$
(15,495
)
 
$
(42,665
)
 
$
7,372

 
$
(58,327
)
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
 
 
 
June 30, 2015
 
December 31, 2014
 
 
 
Derivative
 
Derivative
 
Derivative
 
Derivative
Type
 
Balance Sheet Location
Assets
 
Liabilities
 
Assets
 
Liabilities
Commodity contracts
 
Derivative assets/liabilities – current
$
80,372

 
$

 
$
128,981

 
$

Commodity contracts
 
Derivative assets/liabilities – noncurrent
19,546

 

 
35,897

 

 
 
 
$
99,918

 
$

 
$
164,878

 
$

As of June 30, 2015, we reported a commodity derivative asset of $99.9 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.

9



6.
Property and Equipment
The following table summarizes our property and equipment as of the dates presented: 
 
As of
 
June 30,
 
December 31,
 
2015
 
2014
Oil and gas properties:
 

 
 

Proved
$
3,625,962

 
$
3,390,482

Unproved
128,317

 
125,676

Total oil and gas properties
3,754,279

 
3,516,158

Other property and equipment
76,719

 
75,073

Total properties and equipment
3,830,998

 
3,591,231

Accumulated depreciation, depletion and amortization
(1,942,106
)
 
(1,766,133
)
 
$
1,888,892

 
$
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
 
June 30, 2015
 
December 31, 2014
 
Principal
 
Unamortized Issuance Costs
 
Principal
 
Unamortized Issuance Costs
Revolving credit facility 1
$
212,000

 
 
 
$
35,000

 
 
Senior notes due 2019
300,000

 
$
3,721

 
300,000

 
$
4,131

Senior notes due 2020
775,000

 
18,916

 
775,000

 
20,440

Totals
1,287,000

 
$
22,637

 
1,110,000

 
$
24,571

Long-term debt, net of unamortized issuance costs
$
1,264,363

 
 
 
$
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).
Revolving Credit Facility
The Revolver provides for a revolving commitment and borrowing base of $425 million. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $175 million upon receiving additional commitments from one or more lenders. The Revolver also 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 November 2015 although we expect the borrowing base to be reduced by approximately $30 million prior to the redetermination upon the closing of the sale of our East Texas assets. The Revolver allows for the administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two-thirds of the aggregate commitment. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $1.8 million outstanding as of June 30, 2015. As of June 30, 2015, our available borrowing capacity under the Revolver was $211.2 million.
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 June 30, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 2.1875%, which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 2.00%. 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 June 30, 2015, commitment fees were being charged at a rate of 0.500%.

10



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.
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 plus 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% and are 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 June 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% and are 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.

8.
Income Taxes
Due to the pre-tax operating loss incurred, we recognized a federal income tax benefit for the three and six months ended June 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 also includes a minimal deferred state income tax expense resulting in a combined effective tax rate of 0.2% for the six months ended June 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.2% is due primarily to the valuation allowance placed against our deferred tax assets.
We recognized an income tax benefit for six months ended June 30, 2014 at an effective rate of 34.2% 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.

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.

11



The following table reconciles the obligation as of the dates presented:
 
As of
 
June 30,
 
December 31,
 
2015
 
2014
Balance at beginning of period
$
14,790

 
$
15,993

Accretion
445

 
1,301

Cash payments, net
(1,089
)
 
(2,504
)
Balance at end of period
$
14,146

 
$
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 June 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 $11.4 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.

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

 
 

Tubular inventory and well materials 1
$
4,452

 
$
5,802

Prepaid expenses
3,825

 
4,215

Other
104

 
97

 
$
8,381

 
$
10,114

Other assets:
 

 
 

Assets of supplemental employee retirement plan (“SERP”)
$
4,206

 
$
4,123

Deferred issuance costs of the Revolver
2,021

 
1,623

Other
95

 
95

 
$
6,322

 
$
5,841

Accounts payable and accrued liabilities:
 

 
 

Trade accounts payable
$
84,584

 
$
174,496

Drilling and other lease operating costs
47,872

 
68,842

Royalties
26,263

 
27,883

Compensation – related
12,846

 
9,197

Interest
15,646

 
15,555

Preferred stock dividends
6,067

 
6,067

Other
4,611

 
10,187

 
$
197,889

 
$
312,227

Other liabilities:
 

 
 

Deferred gains on sales of assets
$
91,226

 
$
90,569

Firm transportation obligation
11,390

 
12,042

Asset retirement obligations (“AROs”)
6,191

 
5,889

Defined benefit pension obligations
1,537

 
1,753

Postretirement health care benefit obligations
942

 
890

Compensation – related
1,124

 
7,631

Deferred compensation – SERP obligations and other
4,243

 
4,183

Other
929

 
929

 
$
117,582

 
$
123,886

_______________________
1 We recorded an impairment charge of $1.1 million attributable to surplus tubular inventory and well materials during the three months ended June 30, 2015. We anticipate selling certain of these materials on the surplus market during the second half of 2015.

12



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 June 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
 
June 30, 2015
 
December 31, 2014
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
Senior Notes due 2019
$
255,000

 
$
300,000

 
$
234,000

 
$
300,000

Senior Notes due 2020
695,563

 
775,000

 
620,000

 
775,000

 
$
950,563

 
$
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 June 30, 2015
 
 
Fair Value
 
Fair Value Measurement Classification
Description
 
Measurement
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 

 
 

 
 

 
 

Commodity derivative assets – current
 
$
80,372

 
$

 
$
80,372

 
$

Commodity derivative assets – noncurrent
 
19,546

 

 
19,546

 

Assets of SERP
 
4,206

 
4,206

 

 

Liabilities:
 
 

 
 

 
 

 
 

Deferred compensation – SERP obligations
 
(4,242
)
 
(4,242
)
 

 

 
 
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 six months ended June 30, 2015 and 2014.

13



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 June 30, 2015, we had contractual commitments for two drilling rigs with terms expiring in September 2015 and February 2016, respectively. The minimum commitment under these agreements is $7.0 million for the second half of 2015 and $1.1 million in 2016. In addition, we have a commitment to purchase certain coil tubing services that expires in December 2015. The minimum commitment for the remaining two quarters of 2015 under this agreement is $7.4 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 penalty is based on the number of days remaining in the contractual term. As of June 30, 2015, the penalty amount would have been $13.3 million had we terminated those agreements on that date.
Firm Transportation Commitments
We have entered into contracts for firm transportation capacity rights for specified volumes per day 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 $1.0 million for the second half 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 entered into 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 fee payments regardless of the volume of natural gas production for the first three years of the term. The minimum fee requirement under this agreement is $2.1 million for the second half of 2015 and $5.0 million in 2016.
We have also entered into 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 fourth quarter of 2015. 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 $13.7 million on an annual basis.

14



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 June 30, 2015. In March 2015, we established an additional $0.3 million reserve for litigation attributable to certain properties that we previously sold. This matter was settled in May 2015 with a cash payment of the amount reserved. As of June 30, 2015, we also had AROs of approximately $6.2 million attributable to the plugging of abandoned wells.
 
13.
Shareholders’ Equity
The following tables summarize the components of our shareholders equity and the changes therein as of and for the six months ended June 30, 2015 and 2014:
 
As of
 
 
 
Preferred
 
 
 
 
 
As of
 
December 31,
 
 
 
Stock
 
Dividends
 
All Other
 
June 30,
 
2014
 
Net Loss
 
Offering
 
Declared 1
 
Changes 2
 
2015
Preferred stock
$
4,044

 
$

 
$

 
$

 
$

 
$
4,044

Common stock
529

 

 

 

 
1

 
530

Paid-in capital
1,206,305

 

 

 

 
1,549

 
1,207,854

Accumulated deficit
(535,176
)
 
(137,294
)
 

 
(12,134
)
 

 
(684,604
)
Deferred compensation obligation
3,211

 

 

 

 
143

 
3,354

Accumulated other comprehensive income 3
249

 

 

 

 
(21
)
 
228

Treasury stock
(3,345
)
 

 

 

 
(143
)
 
(3,488
)
 
$
675,817

 
$
(137,294
)
 
$

 
$
(12,134
)
 
$
1,529

 
$
527,918

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

 
$

 
$
3,250

 
$

 
$
(262
)
 
$
4,138

Common stock
466

 

 

 

 
46

 
512

Paid-in capital
891,351

 

 
310,396

 

 
2,477

 
1,204,224

Accumulated deficit
(104,180
)
 
(81,559
)
 

 
(3,440
)
 
(3,368
)
 
(192,547
)
Deferred compensation obligation
2,792

 

 

 

 
209

 
3,001

Accumulated other comprehensive income 3
267

 

 

 

 
49

 
316

Treasury stock
(3,042
)
 

 

 

 
(210
)
 
(3,252
)
 
$
788,804

 
$
(81,559
)
 
$
313,646

 
$
(3,440
)
 
$
(1,059
)
 
$
1,016,392

_______________________
1 Includes dividends of $300.00 per share on 7,945 and 11,480 shares of our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the six months ended June 30, 2015 and 2014, respectively, and $300.00 per share on 32,500 shares of our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the six months ended June 30, 2015.
2 Includes equity-classified share-based compensation of $2,106 and $1,651 for the six months ended June 30, 2015 and 2014.
3 The 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 six months ended June 30, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(32) and $75 and are presented above net of taxes of $(11) and $26.
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.

15




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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Equity-classified awards:
 
 
 
 
 
 
 
Stock option awards
$
387

 
$
329

 
$
780

 
$
790

Common, deferred and restricted stock and stock unit awards
729

 
497

 
1,326

 
861

 
1,116

 
826

 
2,106

 
1,651

Liability-classified awards
(214
)
 
1,047

 
165

 
6,992

 
$
902

 
$
1,873

 
$
2,271

 
$
8,643


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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Interest on borrowings and related fees
$
23,324

 
$
23,778

 
$
46,132

 
$
46,918

Amortization of debt issuance costs
1,176

 
1,039

 
2,280

 
2,051

Capitalized interest
(1,477
)
 
(1,588
)
 
(3,376
)
 
(3,206
)
 
$
23,023

 
$
23,229

 
$
45,036

 
$
45,763




16




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
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Net loss
$
(80,129
)
 
$
(100,784
)
 
$
(137,294
)
 
$
(81,559
)
Less: Preferred stock dividends 1
(6,067
)
 
(1,718
)
 
(12,134
)
 
(3,440
)
Less: Induced conversion of preferred stock

 
(3,368
)
 

 
(3,368
)
Net loss attributable to common shareholders – basic and diluted
$
(86,196
)
 
$
(105,870
)
 
$
(149,428
)
 
$
(88,367
)
 
 
 
 
 
 
 
 
Weighted-average shares – basic
72,398

 
66,514

 
72,330

 
66,065

Effect of dilutive securities 2

 

 

 

Weighted-average shares – diluted
72,398

 
66,514

 
72,330

 
66,065

_______________________
1 Preferred stock dividends were excluded from the computation of diluted earnings per share as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.
2 For the three and six months ended June 30, 2015, approximately 31.3 million and 31.5 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. For the three and six months ended June 30, 2014, approximately 18.8 million and 17.2 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.

17



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;
any impairments, write-downs or write-offs of our reserves or assets;
the projected demand for and supply of oil, NGLs and natural gas;
reductions in the borrowing base under our revolving credit facility, or the Revolver;
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;
our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;
compliance with debt covenants;
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.
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.


18



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 year-over-year changes are presented as not meaningful, or “NM,” where disclosure of the actual value does not otherwise enhance the analysis, and 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 operations in Oklahoma, primarily the Granite Wash, and the Haynesville Shale and Cotton Valley in East Texas, which we have committed to sell as discussed in Key Developments below. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 million barrels of oil equivalent, or MMBOE, including approximately 14 MMBOE of proved reserves attributable to our East Texas operations.
The following table sets forth certain summary operating and financial statistics for the periods presented: 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
 
2015
 
2014
 
2015
 
2014
Total production (MBOE)
2,140

 
1,983

 
4,365

 
3,885

Average daily production (BOEPD)
23,519

 
21,786

 
24,117

 
21,461

Crude oil and NGL production (MBbl)
1,664

 
1,380

 
3,397

 
2,683

Crude oil and NGL production as a percent of total
78
%
 
70
%
 
78
%
 
69
%
Product revenues, as reported
$
83,123

 
$
136,429

 
$
156,258

 
$
269,581

Product revenues, as adjusted for derivatives
$
117,963

 
$
129,207

 
$
228,590

 
$
259,302

Crude oil and NGL revenues as a percent of total, as reported
91
%
 
88
%
 
90
%
 
87
%
Realized prices:
 
 
 
 
 
 
 
Crude oil ($/Bbl)
$
55.22

 
$
100.16

 
$
49.62

 
$
99.16

NGL ($/Bbl)
$
13.53

 
$
30.85

 
$
13.56

 
$
35.71

Natural gas ($/Mcf)
$
2.54

 
$
4.51

 
$
2.73

 
$
4.78

Aggregate ($/BOE)
$
38.84

 
$
68.81

 
$
35.80

 
$
69.40

Operating costs ($/BOE):
 
 
 
 
 
 
 
Lease operating
$
5.10

 
$
6.05

 
$
5.15

 
$
5.69

Gathering, processing and transportation
2.98

 
1.98

 
3.18

 
1.85

Production and ad valorem taxes ($/BOE)
2.32

 
3.79

 
2.21

 
3.81

General and administrative ($/BOE) 1
4.94

 
6.54

 
4.85

 
5.89

Total operating costs ($/BOE)
$
15.34

 
$
18.36

 
$
15.39

 
$
17.24

Depreciation, depletion and amortization ($/BOE)
$
39.91

 
$
36.03

 
$
40.37

 
$
36.97

Cash provided by operating activities
$
52,729

 
$
32,633

 
$
98,281

 
$
99,193

Cash paid for capital expenditures
$
94,999

 
$
190,776

 
$
263,993

 
$
350,580

Cash and cash equivalents at end of period
 
 
 
 
$
4,441

 
$
25,095

Debt outstanding at end of period
 
 
 
 
$
1,287,000

 
$
1,130,000

Credit available under revolving credit facility at end of period 2
 
 
 
 
$
211,196

 
$
393,346

Net development wells drilled and completed
13.5

 
15.0

 
27.6

 
28.8

_______________________
1 Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.52 and $0.42 for the three months ended June 30, 2015 and 2014 and $0.48 and $0.42 for the six months ended June 30, 2015 and 2014 and liability-classified share-based compensation of $(0.10) and $0.53 for the three months ended June 30, 2015 and 2014 and $0.04 and $1.80 for the six months ended June 30, 2015 and 2014.
2 As reduced by outstanding borrowings and letters of credit.


19



In the three months ended June 30, 2015, our crude oil and NGL production increased to 78 percent from 70 percent of our total production compared to the three month period ended June 30, 2014. Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. As of July 24, 2015, we operated 281 producing Eagle Ford wells and had working interests in an additional 36 non-operated producing wells. Through this date, we have accumulated approximately 103,000 net acres in the Eagle Ford. We are currently operating two drilling rigs in the Eagle Ford. Our 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.
To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The Financial Condition 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 six months ended June 30, 2015 and 2014.

Key Developments
The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) depressed commodity prices and our hedging program, (ii) production, development and capital expenditures in the Eagle Ford, (iii) the sale of our East Texas assets and (iv) an amendment to the Revolver decreasing the commitment and borrowing base and modifying our financial covenants, among other things.
Depressed Commodity Prices and Our Hedging Program
Commodity prices continued to be volatile and depressed during the first half of 2015. Our crude oil derivatives supported our liquidity by providing cash settlements of $34.8 million and $71.7 million during the quarter and six months ended June 30, 2015. We have hedged approximately 11,000 barrels of oil per day, or BOPD, or approximately 80 to 90 percent of our expected crude oil production during the second half 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 second half of 2015. No volumes are subject to the put options in 2016. Our natural gas hedges provided cash settlements of $0.7 million during the first quarter of 2015 and expired at the end of that period. We expect to remain unhedged with respect to natural gas production for the foreseeable future.
In May 2015, we were able to add additional crude oil derivatives for calendar year 2016 of 2,000 BOPD with a swap price of $65.00 per barrel. For 2016, we have hedged a total of approximately 6,000 BOPD at weighted-average swap price of $80.41 per barrel.
Production, Development and Capital Expenditures in the Eagle Ford
Our Eagle Ford production was 20,259 BOEPD during the three months ended June 30, 2015 with oil comprising 13,750 BOPD, or 68 percent, and NGLs and natural gas comprising approximately 17 percent and 15 percent, respectively. Our second quarter production represents a five percent decrease compared to 21,390 BOEPD during the three months ended March 31, 2015, of which 14,523 BOPD, or 68 percent, was crude oil, 17 percent was NGLs and 15 percent was natural gas. The sequential decline in production was due primarily to higher gathering line pressures and lower than expected initial production performance of our recent Upper Eagle Ford, or Marl, program. Higher line pressure curtailed production by an estimated 500 BOEPD during the first six months of 2015. We anticipate that this issue will be resolved in the third quarter of 2015 as our midstream transporter is adding additional compression.
During the three months ended June 30, 2015, we completed and turned in line 19 gross (13.5 net) wells in the Eagle Ford for a total of 46 gross (27.6 net) wells on a year-to-date basis. Average well costs for all wells drilled and completed during the three months ended June 30, 2015 declined by approximately $1.7 million, or 19 percent, to $6.9 million from approximately $8.6 million for wells drilled and completed in the first quarter of 2015. This lower overall well cost equates to an approximate 30 percent decrease in well costs since the fourth quarter of 2014 and approximately a 42 percent reduction since the third quarter of 2014. More specifically, the cost of our most recent two-string Lower Eagle Ford wells averaged $5.3 million, while our most recent three-string wells averaged $8.0 million.
Average drilling costs for the three months ended June 30, 2015 decreased 24 percent and 30 percent, respectively, compared to the fourth and third quarters of 2014 due primarily to efficiencies and increased average rates of penetration. Average completion costs for wells over those same time intervals declined by 34 percent and 51 percent, respectively. Approximately half of the cost reduction can be attributed to ongoing optimization and increased efficiencies associated with stimulation design while the remainder is associated with improved vendor pricing for services and materials.

20



Despite disappointing initial production rates of some of our recent Marl wells, we continue to believe that the Marl has significant potential across much of our acreage. Furthermore, we have identified certain factors which we believe contributed to our recent less-than-expected well results in the Marl. First, in the second quarter of 2015, we reduced the amount of proppant pumped per foot of lateral. Analysis has yielded compelling evidence that there is a positive correlation between the amount of proppant pumped and well performance, so we intend to increase proppant in the third quarter. In addition, we have drilled, with favorable results, some Marl wells in the general vicinity of other wells that had disappointing results, with the difference being that the better-performing wells had alternating laterals in the Marl and Lower Eagle Ford that were then “zipper” fracked. Finally, we intend to transition to “slickwater” stimulations. We believe that using this combination of a more complex completion technique of alternating laterals, increasing proppant pumped per stage and transitioning to slickwater stimulations will improve our well results. For the remainder of 2015, while our capital resources are constrained in the current economic environment of continued low oil prices, we are discontinuing Marl drilling and are focusing our efforts on drilling less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where, based on our experience, we expect better rates of return. Preliminarily, we expect to resume multi-well pad drilling of alternating Marl and Lower Eagle Ford wells in 2016.
In consideration of these developments, we anticipate total capital expenditures in 2015 of up to approximately $345 million, which assumes a drilling program utilizing two operated drilling rigs through July with a reduction to a single rig in August 2015. We anticipate that we will incur an early termination charge of approximately $1.3 million in connection with the release of this rig.
Sale of East Texas Assets
In July 2015, we entered into an agreement to sell our Haynesville Shale and Cotton Valley assets in East Texas for gross cash proceeds of $75 million. The sale is expected to close by the end of August 2015 and is subject to customary purchase price adjustments and other customary closing conditions. The effective date of the sale is May 1, 2015.
The properties to be 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 at year-end 2014, as determined by third party engineers, 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.
Amendment to the Revolver
In May 2015, the Revolver was amended to decrease the revolving commitment and borrowing base to $425 million from $450 and $500 million, respectively, in connection with our regular semi-annual redetermination. The decrease was due primarily to substantial declines in commodity prices, partially offset by development of proved undeveloped locations. In addition, the amendment increased the existing leverage ratio (total debt to EBITDAX, a non-GAAP measure) covenant for the remainder of its term, limited certain restricted payments and added a covenant with respect to outstanding borrowings and letters of credit under the Revolver. Please read “Financial Condition – Capitalization: Covenant Compliance” regarding the specific covenants and “Financial Condition – Liquidity” regarding potential future covenant compliance issues.

21



Results of Operations

Production
The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented: 
 
Total Production
 
Average Daily Production
 
Three Months Ended
 
 
 
Three Months Ended
 
 
 
June 30,
 
2015 vs.
 
June 30,
 
2015 vs.
 
2015
 
2014
 
2014
 
2015
 
2014
 
2014
 
(Total volume)
 
(Volume per day)
Crude oil (MBbl and Bbl per day)
1,280

 
1,119

 
161

 
14,064

 
12,298

 
1,767

NGLs (MBbl and Bbl per day)
384

 
261

 
123

 
4,217

 
2,863

 
1,354

Natural gas (MMcf and MMcf per day)
2,860

 
3,618

 
(758
)
 
31

 
40

 
(8
)
Total (MBOE and BOE per day)
2,140

 
1,983

 
158

 
23,519

 
21,786

 
1,732

% Change
 
 
 
 
 
 
 
 
 
 
8
%
 
Three Months Ended
 
 
 
Three Months Ended
 
 
 
June 30,
 
2015 vs.
 
June 30,
 
2015 vs.
 
2015
 
2014
 
2014
 
2015
 
2014
 
2014
 
(MBOE)
 
(BOE per day)
Texas
 
 
 
 
 
 
 
 
 
 
 
South Texas
1,844

 
1,421

 
422

 
20,259

 
15,618

 
4,641

East Texas
173

 
220

 
(47
)
 
1,898

 
2,417

 
(519
)
Mid-Continent
119

 
161

 
(43
)
 
1,302

 
1,770

 
(467
)
Other 1
5

 
180

 
(175
)
 
59

 
1,981

 
(1,922
)
 
2,140

 
1,983

 
158

 
23,519

 
21,786

 
1,732

 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended
 
 
 
Six Months Ended
 
 
 
June 30,
 
2015 vs.
 
June 30,
 
2015 vs.
 
2015
 
2014
 
2014
 
2015
 
2014
 
2014
 
(Total volume)
 
(Volume per day)
Crude oil (MBbl and Bbl per day)
2,617

 
2,195

 
422

 
14,458

 
12,127

 
2,330

NGLs (MBbl and Bbl per day)
781

 
488

 
293

 
4,312

 
2,694

 
1,618

Natural gas (MMcf and MMcf per day)
5,806

 
7,211

 
(1,405
)
 
32

 
40

 
(8
)
Total (MBOE and BOE per day)
4,365

 
3,885

 
481

 
24,116

 
21,461

 
2,655

% Change
 
 
 
 
 
 
 
 
 
 
12
%
 
Six Months Ended
 
 
 
Six Months Ended
 
 
 
June 30,
 
2015 vs.
 
June 30,
 
2015 vs.
 
2015
 
2014
 
2014
 
2015
 
2014
 
2014
 
(MBOE)
 
(BOE per day)
Texas
 
 
 
 
 
 
 
 
 
 
 
South Texas
3,769

 
2,750

 
1,019

 
20,822

 
15,192

 
5,629

East Texas
346

 
435

 
(89
)
 
1,912

 
2,406

 
(494
)
Mid-Continent
239

 
335

 
(95
)
 
1,322

 
1,850

 
(527
)
Other 1
11

 
364

 
(353
)
 
61

 
2,014

 
(1,953
)
 
4,365

 
3,885

 
481

 
24,117

 
21,461

 
2,655

_______________________
1
Comprised of our three active Marcellus Shale wells in Pennsylvania and, for periods through July 2014, our divested Selma Chalk assets in Mississippi.
Total production increased during the three and six months ended June 30, 2015 compared to the corresponding periods of 2014 due primarily to the continued development of our Eagle Ford assets in South Texas. The increase was partially offset by natural production declines in our East Texas and Mid-Continent regions as well as the sale of our Mississippi Selma Chalk assets in July 2014. Approximately 78 percent of total production during both the three and six months ended June 30, 2015 was attributable to oil and NGLs, representing increases of approximately 21 percent and 27 percent, respectively, over the prior year periods. During both the three and six months ended June 30, 2015, our Eagle Ford production represented approximately 86 percent of our total production compared to approximately 72 percent and 71 percent, respectively, from this play during the corresponding periods of 2014.

22



Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:
 
Three Months Ended
 
 
 
Three Months Ended
 
 
 
June 30,
 
2015 vs.
 
June 30,
 
2015 vs.