10-Q 1 pva201263010q.htm 2Q2012 FORM 10-Q PVA 2012.6.30 10Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________________________________________________________________ 
FORM 10-Q 
____________________________________________________________________________
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2012 
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 No.)
 
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.    x  Yes    ¨  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  x  No  ¨
 
Indicate by a 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.
Large accelerated filer
x
 
Accelerated filer
¨
 
 
 
 
 
Non-accelerated filer
¨
(Do not check if a smaller reporting company)
Smaller reporting company
¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). £ Yes x No
 
As of July 27, 2012, 45,877,121 shares of common stock of the registrant were outstanding.


PENN VIRGINIA CORPORATION AND SUBSIDIARIES
 
FORM 10-Q
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012
 
Table of Contents
Item
 
Page
 
Part I - Financial Information
 
 
 
 
1.
 
 
Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2012 and 2011
 
Condensed Consolidated Statements of Comprehensive Income for the Periods Ended June 30, 2012 and 2011
 
Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011
 
Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2012 and 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2.
 
 
 
 
 
 
 
3.
4.
 
Part II - Other Information
 
6.


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 June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Revenues
 

 
 

 
 
 
 
Natural gas
$
10,303

 
$
38,300

 
$
25,189

 
$
79,489

Crude oil
58,382

 
21,548

 
117,105

 
38,131

Natural gas liquids (NGLs)
7,556

 
13,161

 
16,627

 
23,082

Gain (loss) on sales of property and equipment
78

 
(28
)
 
834

 
452

Other
526

 
637

 
1,501

 
1,047

Total revenues
76,845

 
73,618

 
161,256

 
142,201

Operating expenses
 

 
 

 
 
 
 
Lease operating
9,264

 
10,787

 
18,407

 
21,064

Gathering, processing and transportation
4,391

 
4,281

 
8,545

 
8,309

Production and ad valorem taxes
(254
)
 
2,834

 
3,326

 
7,898

General and administrative
11,747

 
12,954

 
23,888

 
26,306

Exploration
9,384

 
19,368

 
17,382

 
48,916

Depreciation, depletion and amortization
51,740

 
33,036

 
102,557

 
67,879

Impairments
28,616

 
71,071

 
28,616

 
71,071

Total operating expenses
114,888

 
154,331

 
202,721

 
251,443

Operating loss
(38,043
)
 
(80,713
)
 
(41,465
)
 
(109,242
)
Other income (expense)
 

 
 

 
 
 
 
Interest expense
(15,084
)
 
(14,143
)
 
(29,858
)
 
(27,627
)
Loss on extinguishment of debt
—

 
(24,238
)
 
—

 
(24,238
)
Derivatives
43,826

 
7,001

 
43,521

 
8,329

Other
28

 
129

 
29

 
273

Loss before income taxes
(9,273
)
 
(111,964
)
 
(27,773
)
 
(152,505
)
Income tax benefit
3,635

 
40,046

 
10,236

 
54,247

Net loss
$
(5,638
)
 
$
(71,918
)
 
$
(17,537
)
 
$
(98,258
)
Loss per share:
 

 
 

 
 
 
 
Basic
$
(0.12
)
 
$
(1.57
)
 
$
(0.38
)
 
$
(2.15
)
Diluted
$
(0.12
)
 
$
(1.57
)
 
$
(0.38
)
 
$
(2.15
)
Weighted average shares outstanding, basic
46,030

 
45,768

 
45,988

 
45,724

Weighted average shares outstanding, diluted
46,030

 
45,768

 
45,988

 
45,724

 
The accompanying notes are an integral part of these condensed consolidated financial statements.

1

PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited
(in thousands)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Net loss
$
(5,638
)
 
$
(71,918
)
 
$
(17,537
)
 
$
(98,258
)
Other comprehensive income:
 

 
 

 
 
 
 
Change in pension and postretirement obligations, net of tax of $13 and $26 in 2012 and $18 and $36 in 2011
23

 
34

 
46

 
68

 
23

 
34

 
46

 
68

Comprehensive loss
$
(5,615
)
 
$
(71,884
)
 
$
(17,491
)
 
$
(98,190
)
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

2

PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited
(in thousands, except share data) 
 
As of
 
June 30,
2012
 
December 31,
2011
Assets
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
11,532

 
$
7,512

Accounts receivable, net of allowance for doubtful accounts
55,751

 
72,432

Derivative assets
26,763

 
18,987

Income taxes receivable
31,154

 
31,465

Other current assets
6,850

 
14,950

Total current assets
132,050

 
145,346

Property and equipment, net (successful efforts method)
1,811,553

 
1,777,575

Derivative assets
12,664

 
—

Other assets
20,805

 
20,132

Total assets
$
1,977,072

 
$
1,943,053

Liabilities and Shareholders’ Equity
 

 
 

Current liabilities
 

 
 

Accounts payable and accrued liabilities
$
84,222

 
$
94,504

Derivative liabilities
617

 
3,549

Deferred income taxes
3,807

 
3,808

Current portion of long-term debt
4,837

 
4,746

Total current liabilities
93,483

 
106,607

Other liabilities
16,575

 
15,887

Derivative liabilities
1,651

 
6,850

Deferred income taxes
264,631

 
274,839

Long-term debt
774,144

 
692,561

Commitments and contingencies (Note 10)
 

 
 

Shareholders’ equity:
 

 
 

Preferred stock of $100 par value – 100,000 shares authorized; none issued
—

 
—

Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued of 45,877,121 and 45,714,191 as of June 30, 2012 and December 31, 2011, respectively
271

 
270

Paid-in capital
693,078

 
690,131

Retained earnings
134,529

 
157,242

Deferred compensation obligation
3,032

 
3,620

Accumulated other comprehensive loss
(1,038
)
 
(1,084
)
Treasury stock – 202,875 and 223,886 shares of common stock, at cost, as of June 30, 2012 and December 31, 2011, respectively
(3,284
)
 
(3,870
)
Total shareholders’ equity
826,588

 
846,309

Total liabilities and shareholders’ equity
$
1,977,072

 
$
1,943,053

 
The accompanying notes are an integral part of these condensed consolidated financial statements.

3

PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited
(in thousands)
 
Six Months Ended June 30,
 
2012
 
2011
Cash flows from operating activities
 

 
 

Net loss
$
(17,537
)
 
$
(98,258
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Non-cash portion of loss on extinguishment of debt
—

 
21,822

Depreciation, depletion and amortization
102,557

 
67,879

Impairments
28,616

 
71,071

Derivative contracts:
 

 
 

Net gains
(43,521
)
 
(8,329
)
Cash settlements
14,951

 
11,775

Deferred income tax benefit
(10,236
)
 
(54,247
)
Gain on sales of property and equipment, net
(834
)
 
(452
)
Non-cash exploration expense
16,455

 
41,081

Non-cash interest expense
2,050

 
4,750

Share-based compensation (equity-classified)
2,951

 
3,809

Other, net
203

 
265

Changes in operating assets and liabilities, net
20,070

 
2,593

Net cash provided by operating activities
115,725

 
63,759

Cash flows from investing activities
 

 
 

Capital expenditures - property and equipment
(188,236
)
 
(211,081
)
Proceeds from sales of property and equipment, net
527

 
696

Other, net
180

 
100

Net cash used in investing activities
(187,529
)
 
(210,285
)
Cash flows from financing activities
 

 
 

Dividends paid
(5,176
)
 
(5,156
)
Proceeds from revolving credit facility borrowings
84,000

 
—

Repayment of revolving credit facility borrowings
(3,000
)
 
—

Proceeds from the issuance of senior notes
—

 
300,000

Repurchase of Convertible Notes
—

 
(232,963
)
Debt issuance costs paid
—

 
(6,559
)
Other, net
—

 
974

Net cash provided by financing activities
75,824

 
56,296

Net increase (decrease) in cash and cash equivalents
4,020

 
(90,230
)
Cash and cash equivalents - beginning of period
7,512

 
120,911

Cash and cash equivalents - end of period
$
11,532

 
$
30,681

Supplemental disclosures:
 

 
 

Cash paid for:
 

 
 

Interest (net of amounts capitalized)
$
26,656

 
$
19,705

Income taxes (net of refunds received)
$
(311
)
 
$
(96
)
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

4

PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited
For the Quarterly Period Ended June 30, 2012
(in thousands, except per share amounts)
 
1.
Organization

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in various domestic onshore regions including Texas, Appalachia, the Mid-Continent and Mississippi.

 
2.
Basis of Presentation
 
Our Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America. 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, 2011. Operating results for the six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Certain amounts for the 2011 period have been reclassified to conform to the current year presentation.
 
During the quarter ended June 30, 2012, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Condensed Consolidated Financial Statements and Notes.
 
Management has evaluated all activities of the Company through the date upon which the Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of substantially all of our assets in the Appalachian region on July 31, 2012 (see Note 3), no subsequent events have occurred that would require recognition in the Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.

3.
Acquisitions and Divestitures
 
Property Acquisitions
 
Eagle Ford Property Acquisitions
 
In December 2011, we entered into an agreement with an industry partner to jointly explore a 13,500 acre area of mutual interest ("AMI") in Lavaca County, Texas. Under the terms of the agreement, we must commence drilling on six wells by September 1, 2012 to earn our entire interest in the acreage and must carry our partner on its working interest share of the costs of the first three wells. We drilled four (3.8 net) successful exploratory wells on the acreage in the six months ended June 30, 2012. Depending upon the future participation elections made by our partners, our ultimate working interest in wells drilled in the AMI is expected to be at least 57%.
 
Divestitures
 
Oil and Gas Properties
 
On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and customary purchase and sale adjustments. The transaction had an effective date of January 1, 2012. The properties sold included vertical and horizontal coalbed methane and conventional properties as well as royalty interests. The properties had net production of approximately 20 million cubic feet of natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. Estimated proved reserves associated with the properties, as determined by our third party reserve engineers as of December 31, 2011, were approximately 106 billion cubic feet of natural gas equivalent, of which 96 percent were proved developed and 100 percent were natural gas. Also included in the group of assets sold was a gathering system. During the quarter ended June 30, 2012, we recognized an impairment of $28.6 million with

5
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

respect to these assets.

In January 2012, we sold our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania for proceeds of $1.0 million, net of transaction costs. We recognized a gain of $0.6 million in connection with this transaction.

4.
Accounts Receivable and Major Customers
 
The following table summarizes our accounts receivable by type as of the dates presented:
 
June 30,
2012
 
December 31,
2011
Customers
$
35,603

 
$
49,763

Joint interest partners
18,516

 
22,755

Other
2,895

 
1,695

 
57,014

 
74,213

Less: Allowance for doubtful accounts
(1,263
)
 
(1,781
)
 
$
55,751

 
$
72,432


For the six months ended June 30, 2012 and 2011, six customers accounted for $79.5 million and $95.4 million, or approximately 50% and 68%, of our total consolidated product revenues. As of June 30, 2012 and December 31, 2011, $14.4 million and $29.8 million, or approximately 26% and 41%, of our consolidated accounts receivable, including joint interest billings, related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by these customers.

5.
Derivative Instruments
 
We utilize derivative instruments to mitigate our financial exposure to natural gas and crude oil price volatility as well as the volatility in interest rates attributable to our debt instruments. We are not engaged in the trading of derivative instruments for speculative purposes. The derivative instruments are placed with financial institutions that we believe are acceptable credit risks. Our derivative instruments are not formally designated as hedges.
 
Commodity Derivatives
 
We utilize collars, swaps, and swaptions 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. As of June 30, 2012, we have hedged our future crude oil production through 2014 to the greatest extent permitted by our revolving credit agreement (the "Revolver") and our internal policies.

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.
 

6
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table sets forth our commodity derivative positions as of June 30, 2012:
 
 
 
Average
Volume Per
Day
 
Weighted Average Price
 
Fair Value
 
Instrument
 
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Natural Gas: 
 
 
(in MMBtu)
 
($/MMBtu)
 
 

 
 

 
 

Third quarter 2012
Swaps
 
20,000

 
$
5.31

 
 

 
$
4,594

 
$
—

Fourth quarter 2012
Swaps
 
10,000

 
$
5.10

 
 

 
1,824

 
—

Crude Oil:
 
 
(barrels)
 
($/barrel)
 
 

 
 

 
 
Third quarter 2012
Collars
 
1,000

 
$
90.00

 
$
97.00

 
519

 
—

Fourth quarter 2012
Collars
 
1,000

 
$
90.00

 
$
97.00

 
512

 
—

First quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
518

 
—

Second quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
491

 
—

Third quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
503

 
—

Fourth quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
521

 
—

Third quarter 2012
Swaps
 
3,000

 
$
104.40

 
 

 
5,204

 
—

Fourth quarter 2012
Swaps
 
3,000

 
$
104.40

 
 

 
4,817

 
—

First quarter 2013
Swaps
 
2,250

 
$
103.51

 
 

 
3,108

 
—

Second quarter 2013
Swaps
 
2,250

 
$
103.51

 
 

 
3,004

 
—

Third quarter 2013
Swaps
 
1,500

 
$
102.77

 
 

 
1,916

 
—

Fourth quarter 2013
Swaps
 
1,500

 
$
102.77

 
 

 
1,940

 
—

First quarter 2014
Swaps
 
2,000

 
$
100.44

 
 

 
2,166

 
—

Second quarter 2014
Swaps
 
2,000

 
$
100.44

 
 

 
2,232

 
—

Third quarter 2014
Swaps
 
1,500

 
$
100.20

 
 

 
1,687

 
—

Fourth quarter 2014
Swaps
 
1,500

 
$
100.20

 
 

 
1,699

 
—

First quarter 2013
Swaption
 
1,100

 
$
100.00

 
 

 
—

 
290

Second quarter 2013
Swaption
 
1,000

 
$
100.00

 
 

 
—

 
241

Third quarter 2013
Swaption
 
900

 
$
100.00

 
 

 
—

 
180

Fourth quarter 2013
Swaption
 
750

 
$
100.00

 
 

 
—

 
117

First quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
338

Second quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
338

Third quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
339

Fourth quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
339

Settlements to be received in subsequent period
 
 

 
 

 
 

 
2,086

 
—

 
Interest Rate Swaps
 
In February 2012, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (“2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds.
 
During the six months ended June 30, 2011, we had an interest rate swap agreement in effect that established variable rates on approximately one-third of the face amount of the outstanding obligation under our 10.375% Senior Notes due 2016 (“2016 Senior Notes"). In August 2011, we terminated this agreement and received $2.9 million in cash proceeds.

As of June 30, 2012, we had no interest rate derivative instruments outstanding.
 

7
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Financial Statement Impact of Derivatives
 
The impact of our derivative 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 June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Impact by contract type:
 

 
 

 
 
 
 
Commodity contracts
$
41,821

 
$
5,997

 
$
42,115

 
$
7,305

Interest rate contracts
2,005

 
1,004

 
1,406

 
1,024

 
$
43,826

 
$
7,001

 
$
43,521

 
$
8,329

Realized and unrealized impact:
 

 
 

 
 
 
 
Cash received for:
 

 
 

 
 
 
 
Commodity contract settlements
$
5,564

 
$
4,133

 
$
13,545

 
$
10,877

Interest rate contract settlements
1,406

 
898

 
1,406

 
898

 
6,970

 
5,031

 
14,951

 
11,775

Unrealized gains (losses) attributable to:
 

 
 

 
 
 
 
Commodity contracts
36,257

 
1,864

 
28,570

 
(3,572
)
Interest rate contracts
599

 
106

 
—

 
126

 
36,856

 
1,970

 
28,570

 
(3,446
)
 
$
43,826

 
$
7,001

 
$
43,521

 
$
8,329

 
The effects of derivative gains (losses) and cash settlements of our commodity and interest rate 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: Net gains and Derivative contracts: Cash settlements captions on our Condensed Consolidated Statements of Cash Flows.
 
The following table summarizes the fair value 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, 2012
 
December 31, 2011
Type
 
Balance Sheet Location
 
Derivative
Assets
 
Derivative
Liabilities
 
Derivative
Assets
 
Derivative
Liabilities
Commodity contracts
 
Derivative assets/liabilities - current
 
$
26,763

 
$
617

 
$
18,987

 
$
3,549

Interest rate contracts
 
Derivative assets/liabilities - current
 
—

 
—

 
—

 
—

 
 
 
 
26,763

 
617

 
18,987

 
3,549

Commodity contracts
 
Derivative assets/liabilities - noncurrent
 
12,664

 
1,651

 
—

 
6,850

Interest rate contracts
 
Derivative assets/liabilities - noncurrent
 
—

 
—

 
—

 
—

 
 
 
 
12,664

 
1,651

 
—

 
6,850

 
 
 
 
$
39,427

 
$
2,268

 
$
18,987

 
$
10,399

 
As of June 30, 2012, we reported a commodity derivative asset of $39.4 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three 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 not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

8
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


6.
Property and Equipment
 
The following table summarizes our property and equipment as of the dates presented:
 
June 30,
2012
 
December 31,
2011
Oil and gas properties:
 

 
 

Proved
$
2,380,954

 
$
2,239,186

Unproved
106,181

 
120,288

Total oil and gas properties
2,487,135

 
2,359,474

Other property and equipment
151,929

 
143,285

Total property and equipment
2,639,064

 
2,502,759

Accumulated depreciation, depletion and amortization
(827,511
)
 
(725,184
)
 
$
1,811,553

 
$
1,777,575

 
7.
Long-Term Debt
 
The following table summarizes our long-term debt as of the dates presented:
 
June 30,
2012
 
December 31,
2011
Revolving credit facility
$
180,000

 
$
99,000

Senior notes due 2016, net of discount (principal amount of $300,000)
294,144

 
293,561

Senior notes due 2019
300,000

 
300,000

Convertible notes due 2012, net of discount (principal amount of $4,915)
4,837

 
4,746

 
778,981

 
697,307

Less: Current portion of long-term debt
(4,837
)
 
(4,746
)
 
$
774,144

 
$
692,561

 
Revolving Credit Facility
 
In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver has a borrowing base that is redetermined semi-annually. Upon the closing of the sale of our assets in the Appalachian region on July 31, 2012, our borrowing base under the Revolver was decreased by $70 million to a level of $230 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. We had letters of credit of $1.7 million outstanding as of June 30, 2012. As of June 30, 2012, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $118.3 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 (the “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%, and, in each case, plus 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. Commitment fees are charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2012, the effective interest rate on the borrowings under the Revolver was 2.2500%.
 
The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.5 to 1.0 reducing to 4.0

9
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

to 1.0 for periods ending after June 30, 2013.
 
The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries (“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 guarantees provided by the parent company and the Guarantor Subsidiaries under the Revolver as well as those provided for the senior indebtedness described below 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 or any of the Guarantor Subsidiaries to obtain funds through dividends or other means, including advances and intercompany notes, among others.
 
2016 Senior Notes
 
The 2016 Senior Notes were originally sold at 97% of par equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. Beginning in June 2013, we may redeem all or part of the 2016 Senior Notes at a redemption price starting at 105.188% of the principal amount and reducing to 100% in June 2015 and thereafter. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2019 Senior Notes
 
The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. Beginning in April 2015, we may redeem all or part of the 2019 Senior Notes at a redemption price starting at 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 effectively subordinated to all of 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.
 
Convertible Notes
 
The 4.50% Convertible Senior Subordinated Notes due 2012 (“Convertible Notes”) bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes rank senior in right of payment to any of our future junior subordinated indebtedness and structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.
 
The Convertible Notes are represented by a liability component classified as current maturities of long-term debt, net of discount, and an equity component representing the convertible feature which is included in additional paid-in capital in shareholders’ equity. The effective interest rate on the liability component of the Convertible Notes for all periods presented was 8.5%. The $4.9 million of outstanding principal amount due on the Convertible Notes will be paid on November 15, 2012 and will be funded by cash on hand or by borrowings under the Revolver.
 
In connection with a tender offer completed in April 2011, the Company repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, including a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded from the net proceeds of the 2019 Senior Notes offering.
 

10
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the carrying amount of the components of the Convertible Notes as of the dates presented: 
 
June 30,
2012
 
December 31,
2011
Principal
$
4,915

 
$
4,915

Unamortized discount
(78
)
 
(169
)
Net carrying amount of liability component
$
4,837

 
$
4,746

Carrying amount of equity component
$
35,201

 
$
35,201


The following table summarizes the amounts recognized as components of interest expense attributable to the Convertible Notes for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Contractual interest expense
$
56

 
$
421

 
$
111

 
$
3,009

Accretion on original issue discount
46

 
318

 
91

 
2,265

Amortization of debt issuance costs
7

 
55

 
14

 
389

 
$
109

 
$
794

 
$
216

 
$
5,663

8.
Additional Balance Sheet Detail
 
The following table summarizes components of selected balance sheet accounts as of the dates presented:
 
June 30,
2012
 
December 31,
2011
Other current assets:
 

 
 

Tubular inventory and well materials
$
5,588

 
$
14,251

Prepaid expenses
1,262

 
699

 
$
6,850

 
$
14,950

Other assets:
 

 
 

Debt issuance costs
$
15,617

 
$
16,993

Assets of supplemental employee retirement plan ("SERP")
3,298

 
3,088

Other
1,890

 
51

 
$
20,805

 
$
20,132

Accounts payable and accrued liabilities:
 

 
 

Trade accounts payable
$
37,040

 
$
30,186

Drilling costs
16,116

 
30,948

Royalties
11,977

 
15,235

Production and franchise taxes
5,881

 
3,495

Compensation
4,827

 
5,186

Interest
6,208

 
5,964

Other
2,173

 
3,490

 
$
84,222

 
$
94,504

Other liabilities:
 

 
 

Asset retirement obligations
$
6,440

 
$
6,283

Defined benefit pension obligations
1,694

 
1,763

Postretirement health care benefit obligations
3,011

 
3,022

Deferred compensation - SERP obligation and other
3,416

 
3,172

Other
2,014

 
1,647

 
$
16,575

 
$
15,887


11
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 
9.
Fair Value Measurements
 
We apply the authoritative accounting provisions for measuring the fair values 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. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.
 
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, 2012, 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:
 
June 30, 2012
 
December 31, 2011
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
Senior Notes due 2016
$
285,000

 
$
294,144

 
$
319,500

 
$
293,561

Senior Notes due 2019
244,500

 
300,000

 
280,500

 
300,000

Convertible Notes
4,915

 
4,837

 
4,925

 
4,746

 
$
534,415

 
$
598,981

 
$
604,925

 
$
598,307

 
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 fair values of those assets and liabilities as of the dates presented:
 
As of June 30, 2012
 
Fair Value
Measurement
 
Fair Value Measurement Classification
Description
 
Level 1
 
Level 2
 
Level 3
Assets:
 

 
 

 
 

 
 

Commodity derivative assets - current
$
26,763

 
$
—

 
$
26,763

 
$
—

Commodity derivative assets - noncurrent
12,664

 
—

 
12,664

 
—

Assets of SERP
3,298

 
3,298

 
—

 
—

Liabilities:
 

 
 

 
 

 
 

Commodity derivative liabilities - current
(617
)
 
—

 
(617
)
 
—

Commodity derivative liabilities - noncurrent
(1,651
)
 
—

 
(1,651
)
 
—

Deferred compensation - SERP obligation and other
(3,411
)
 
(3,411
)
 
—

 
—

 
$
37,046

 
$
(113
)
 
$
37,159

 
$
—

 
 
 
 
 
 
 
 
 
As of December 31, 2011
 
Fair Value
Measurement
 
Fair Value Measurement Classification
Description
 
Level 1
 
Level 2
 
Level 3
Assets:
 

 
 

 
 

 
 

Commodity derivative assets – current
$
18,987

 
$
—

 
$
18,987

 
$
—

Assets of SERP
3,088

 
3,088

 
—

 
—

Liabilities:
 

 
 

 
 

 
 

Commodity derivative liabilities - current
(3,549
)
 
—

 
(3,549
)
 
—

Commodity derivative liabilities - noncurrent
(6,850
)
 
—

 
(6,850
)
 
—

Deferred compensation - SERP obligation and other
(3,168
)
 
(3,168
)
 
—

 
—

 
$
8,508

 
$
(80
)
 
$
8,588

 
$
—


12
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 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 three or six months ended June 30, 2012 and 2011.

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 NYMEX Henry Hub gas and West Texas Intermediate crude oil 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 obligation and other: 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 include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of asset retirement obligations (“AROs”). The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved and probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs 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 fair value estimates as level 3 inputs.
 
10.
Commitments and Contingencies
 
Commitments
 
Our most significant commitments consist of the purchase of oil and gas well drilling services, capacity utilization under firm transportation service agreements and operating leases for field and office equipment and office space, as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.

We have contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we will no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we expect to record a charge of approximately $15 million to $18 million in the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.
 
Contingencies - 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 pertaining to certain properties that remains outstanding as of June 30, 2012. In addition, as of June 30, 2012, we have an ARO liability of approximately $6.4 million attributable to the plugging of abandoned wells.

13
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


11.
Shareholders’ Equity
 
The following table summarizes the components of our shareholders’ equity and the changes therein as of and for the six months ended June 30, 2012 and 2011:
 
Balance as of December 31, 2011
 
Net Loss
 
Dividends Paid
($0.1125
per share)
 
All Other
Changes
 
Balance as of June 30, 2012
Common stock
$
270

 
$
—

 
$
—

 
$
1

 
$
271

Paid-in capital
690,131

 
—

 
—

 
2,947

 
693,078

Retained earnings
157,242

 
(17,537
)
 
(5,176
)
 
—

 
134,529

Deferred compensation obligation
3,620

 
—

 
—

 
(588
)
 
3,032

Accumulated other comprehensive loss
(1,084
)
 
—

 
—

 
46

 
(1,038
)
Treasury stock
(3,870
)
 
—

 
—

 
586

 
(3,284
)
Total shareholders' equity
$
846,309

 
$
(17,537
)
 
$
(5,176
)
 
$
2,992

 
$
826,588

 
 
Balance as of December 31, 2010
 
Net Loss
 
Dividends Paid
($0.1125
per share)
 
All Other
Changes
 
Balance as of June 30, 2011
Common stock
$
267

 
$
—

 
$
—

 
$
2

 
$
269

Paid-in capital
680,981

 
—

 
—

 
4,578

 
685,559

Retained earnings
300,473

 
(98,258
)
 
(5,156
)
 
—

 
197,059

Deferred compensation obligation
2,743

 
—

 
—

 
492

 
3,235

Accumulated other comprehensive loss
(938
)
 
—

 
—

 
68

 
(870
)
Treasury stock
(3,250
)
 
—

 
—

 
(395
)
 
(3,645
)
Total shareholders' equity
$
980,276

 
$
(98,258
)
 
$
(5,156
)
 
$
4,745

 
$
881,607

 
12.
Share-Based Compensation

Our stock compensation plans permit 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. Generally, stock options granted under our stock compensation plans vest over a three-year period, with one-third vesting in each year. Common stock and deferred common stock units granted under our stock compensation plans vest immediately, and we recognize compensation expense related to those grants on the grant date. Restricted stock and restricted stock units granted under our stock compensation plans vest over a three-year period, either at the end of the three years or with one-third vesting in each year. We recognize compensation expense related to our stock compensation plans in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations.
 
Equity-Classified Awards

Most of the awards issued under our stock compensation plans 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 recognition of compensation cost attributable to these awards is a non-cash item of expense.
 
Liability-Classified Awards
 
In February 2012, we granted performance-based restricted stock units (“PBRSUs”) to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.
 
Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period based on the fair value derived from a Monte Carlo model and recognized based on the period of time that has elapsed during each of the individual performance periods.

14
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

 The following table summarizes share-based compensation expense recognized for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Equity-classified awards:
 

 
 

 
 
 
 
Stock option plans
$
950

 
$
1,379

 
$
2,158

 
$
2,787

Common, deferred, restricted and time-based restricted unit plans
386

 
634

 
793

 
1,022

 
1,336

 
2,013

 
2,951

 
3,809

Liability-classified awards
553

 
—

 
625

 
—

 
$
1,889

 
$
2,013

 
$
3,576

 
$
3,809

 
13.
Restructuring Activities
 
During 2011, we completed an organizational restructuring due primarily to our decision to exit the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. We terminated approximately 40 employees and closed our regional office in Tulsa, Oklahoma. Accordingly, we recorded a charge and recognized an obligation in connection with the long-term lease of that office. Activities recorded during the periods ended June 30, 2012 that were attributable to this restructuring included cash payments and accretion of the lease obligation and the cash payment of termination benefits accrued during 2011. In addition, we adjusted the lease obligation as a result of a change in estimated sub-lease rental income. Activities recorded during the periods ended June 30, 2011 are attributable to restructuring actions taken during periods prior to 2011. Restructuring charges, including the accretion of the lease obligation, are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations.
 
The following table summarizes our restructuring-related obligations as of and for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Balance at beginning of period
$
475

 
$
—

 
$
576

 
$
64

Employee, office and other costs accrued
(145
)
 
52

 
(148
)
 
70

Cash payments, net
(79
)
 
(52
)
 
(177
)
 
(134
)
Balance at end of period
$
251

 
$
—

 
$
251

 
$
—

 
In the third quarter of 2012, we expect to record restructuring and certain exit costs in connection with the sale of our Appalachian properties, including those attributable to the planned closing of our office in Canonsburg, Pennsylvania.

14.
Impairments
 
The following table summarizes impairment charges recorded during the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Oil and gas properties
$
28,481

 
$
71,071

 
$
28,481

 
$
71,071

Other
135

 
—

 
135

 
—

 
$
28,616

 
$
71,071

 
$
28,616

 
$
71,071


During the quarter ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the quarter ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

15
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


15.
Interest Expense
 
The following table summarizes the components of interest expense for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Interest on borrowings and related fees
$
14,289

 
$
13,120

 
$
28,306

 
$
23,867

Accretion on original issue discount
341

 
583

 
674

 
2,788

Amortization of debt issuance costs
694

 
895

 
1,376

 
1,962

Capitalized interest
(240
)
 
(455
)
 
(498
)
 
(990
)
 
$
15,084

 
$
14,143

 
$
29,858

 
$
27,627

 
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 June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Net loss
$
(5,638
)
 
$
(71,918
)
 
$
(17,537
)
 
$
(98,258
)
Weighted-average shares, basic
46,030

 
45,768

 
45,988

 
45,724

Effect of dilutive securities 1
—

 
—

 
—

 
—

Weighted-average shares, diluted
46,030

 
45,768

 
45,988

 
45,724

____________________________________________________________________________
1 For each of the three and six month periods ended June 30, 2012 and 2011, an amount less than 0.1 million of potentially dilutive securities, including the Convertible Notes, stock options, restricted stock and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.


16

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 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 and natural gas;
•
our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;
•
our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
•
any impairments, write-downs or write-offs of our reserves or assets;
•
the projected demand for and supply of oil, natural gas liquids and natural gas;
•
reductions in the borrowing base under our revolving credit facility;
•
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 gas reserves;
•
drilling and operating risks;
•
our ability to compete effectively against other independent and major oil and natural gas companies;
•
our ability to successfully monetize select assets and repay our debt;
•
leasehold terms expiring before production can be established;
•
environmental 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;
•
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 their ability to meet their future obligations;
•
changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;
•
uncertainties relating to general domestic and international economic and political conditions; and
•
other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

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. 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.

17

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.

Overview of Business
 
We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in various domestic onshore regions. We have a geographically diverse asset base with areas of operations in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of December 31, 2011, we had proved natural gas and oil reserves of approximately 883 billion cubic feet equivalent, or Bcfe. As discussed in the Key Developments that follow, our total reserves were reduced by approximately106 Bcfe subsequent to the sale of our Appalachian properties in July 2012. Our current operations include primarily the drilling of unconventional development wells and exploring for primarily unconventional reserves.

We are currently focused on the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in our Mid-Continent region through participation in wells drilled by our joint venture partner.
 
The following table sets forth certain summary operating and financial statistics for the periods presented:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2012
 
2011
 
2012
 
2011
Total production (MMcfe)
10,653

 
11,699

 
21,527

 
23,870

Daily production (MMcfe per day)
117.1

 
128.5

 
118.3

 
132.0

Daily gas production (MMcf per day)
64.4

 
97.4

 
66.8

 
102.7

Daily oil and NGL production (Bbl per day)
8,780

 
5,180

 
8,570

 
4,860

Product revenues, as reported
$
76,241

 
$
73,009

 
$
158,921

 
$
140,702

Product revenues, as adjusted for derivatives
$
81,806

 
$
77,142

 
$
172,467

 
$
151,579

Operating loss
$
(38,043
)
 
$
(80,713
)
 
$
(41,465
)
 
$
(109,242
)
Interest expense
$
15,084

 
$
14,143

 
$
29,858

 
$
27,627

Cash provided by operating activities
$
45,024

 
$
34,323

 
$
115,725

 
$
63,759

Cash paid for capital expenditures
$
93,767

 
$
110,352

 
$
188,236

 
$
211,081

Cash and cash equivalents at end of period
 
 
 
 
$
11,532

 
$
30,681

Debt outstanding, net of discounts, at end of period
 
 
 
 
$
778,981

 
$
597,668

Credit available under revolving credit facility at end of period 1
 
 
 
 
$
118,282

 
$
160,730

Net development wells drilled
4.7

 
12.0

 
12.2

 
14.4

Net exploratory wells drilled
2.9

 
1.1

 
4.8

 
6.4

 
1 As reduced by outstanding borrowings and letters of credit and limited by financial covenants, if applicable.
 

18


Key Developments

Through the date of filing this Quarterly Report on Form 10-Q, the following general business developments and corporate actions had an impact on the financial reporting and disclosure of our results of operations and financial position: (i) drilling results in the Eagle Ford Shale and other plays, (ii) continuing to shift the focus of our production from natural gas to crude oil and natural gas liquids, or NGLs, (iii) executing an agreement to sell our Appalachian assets and (iv) hedging a portion of our crude oil production for the calendar years 2012 through 2014 to the levels permitted by our revolving credit agreement, or Revolver, and our internal policies.
 
Drilling Results and Future Development

During the six months ended June 30, 2012, we drilled a total of 20 gross (16.9 net) wells, including 14 gross (11.7 net) development wells and five gross (4.7 net) exploratory wells in the Eagle Ford Shale and one gross (0.5 net) development well in the Granite Wash.
 
We currently have two rigs drilling in the Eagle Ford Shale. We have drilled a total of 53 wells since we began drilling operations in this play during the first half of 2011. Of the total wells drilled, 51 (42.0 net) wells are producing and two are in progress as of July 31, 2012. The average peak gross production rate per well for 44 of these wells which had full-length laterals was approximately 1,001 barrels of oil equivalent per day, or BOEPD. Our Eagle Ford Shale production was approximately 6,550 net BOEPD during the second quarter of 2012, with oil comprising 84 percent, NGLs comprising nine percent and natural gas comprising seven percent. We have allocated over 90 percent of our capital expenditures during 2012 to activities in the Eagle Ford Shale.
 
Included in the totals presented above for the Eagle Ford Shale are our first four (3.8 net) exploratory wells in Lavaca County, Texas drilled in connection with a joint exploration agreement with an industry partner that we entered into in December 2011. Under the terms of the agreement, we must commence drilling on six wells by September 1, 2012 to earn our entire interest in the 13,500 acre area of mutual interest, or AMI, and must carry our partner on its working interest share of the costs of the first three wells. We are currently drilling our fifth well of the six well obligation and based on our progress through July 31, 2012, we expect to complete this requirement and earn our maximum interest in approximately 8,000 net acres. Depending upon the future participation elections made by our partners, our ultimate working interest in wells drilled in the AMI is expected to be at least 57%.
 
Production Focus
 
During the past two years, we have allocated approximately 80% of our capital expenditures to explore and develop primarily oil and NGL-rich areas, primarily in the Eagle Ford Shale in South Texas. Accordingly, we are continuing to transform our production profile away from natural gas to oil and NGLs. Approximately 44% of our total production on an equivalent basis during the six months ended June 30, 2012 was attributable to oil and NGLs, an increase of approximately 76% over the prior year period and approximately 5% over the three month period ended March 31, 2012. For the six months ended June 30, 2012, approximately 84% of our product revenues were attributable to oil and NGLs, an increase of approximately 118% over the corresponding prior year period.

Disposition of Appalachian Assets

On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and purchase and sale adjustments. The transaction had an effective date of January 1, 2012. The properties sold included vertical and horizontal coalbed methane and conventional properties as well as royalty interests. The properties had net production of approximately 20 million cubic feet of natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. As a result of the divestiture, our 2012 production will decrease by an estimated 2.9 Bcfe. Estimated proved reserves associated with the properties, as determined by our third party reserve engineers as of December 31, 2011, were approximately 106 Bcfe, of which 96 percent were proved developed and 100 percent were natural gas. Also included in the group of assets sold was a gathering system. Upon the closing of the transaction, our borrowing base under the Revolver was decreased by $70 million to a level of $230 million.

During the quarter ended June 30, 2012, we recognized an impairment of $28.6 million with respect to these assets. In the third quarter of 2012, we expect to record certain restructuring and exit costs in connection with the sale, including those attributable to the planned closing of our office in Canonsburg, Pennsylvania. Furthermore, we have contractual commitments

19

for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we will no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we expect to record a charge of approximately $15 million to $18 million in the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Commodity Hedging Activities
 
In January 2012, we amended our Revolver to expand the potential volume available for hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves. As of June 30, 2012, we have hedged the maximum volume of oil production as permitted under the terms of the Revolver for calendar years 2012 through 2014. For the remainder of 2012, we have hedged approximately 67 percent of our estimated oil production at weighted-average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel. For 2013, we have approximately 35 to 40 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $98.61 and $102.09 per barrel. For 2014, we have approximately 15 to 20 percent of our estimated oil production hedged at a weighted-average swap price of $100.33 per barrel. Our natural gas hedges represent approximately 32 percent of our estimated production for the balance of the year at a weighted-average swap price of $5.24 per MMBtu. At this time, we have no hedges in place for our estimated natural gas production beyond 2012.



20

Results of Operations
 
Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011
 
The following table sets forth a summary of certain operating and financial performance for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Total Production:
 
 
 
 
 
 
 
  Natural gas (MMcf)
5,859

 
8,869

 
(3,010
)
 
(34
)%
  Crude oil (MBbl)
572

 
219

 
353

 
161
 %
  NGLs (MBbl)
227

 
253

 
(26
)
 
(10
)%
     Total production (MMcfe)
10,653

 
11,699

 
(1,046
)
 
(9
)%
Realized prices, before derivatives:
 
 
 
 
 
 
 
  Natural gas ($/Mcf)
$
1.76

 
$
4.32

 
$
(2.56
)
 
(59
)%
  Crude oil ($/Bbl)
102.14

 
98.48

 
3.66

 
4
 %
  NGLs ($/Bbl)
33.23

 
52.04

 
(18.81
)
 
(36
)%
     Total ($/Mcfe)
$
7.16

 
$
6.24

 
$
0.92

 
15
 %
Revenues
 
 
 
 
 
 
 
Natural gas
$
10,303

 
$
38,300

 
$
(27,997
)
 
(73
)%
Crude oil
58,382

 
21,548

 
36,834

 
171
 %
Natural gas liquids (NGLs)
7,556

 
13,161

 
(5,605
)
 
(43
)%
Total product revenues
76,241

 
73,009

 
3,232

 
4
 %
Gain on sales of property and equipment, net
78

 
(28
)
 
106

 
NM

Other
526

 
637

 
(111
)
 
(17
)%
Total revenues
76,845

 
73,618

 
3,227

 
4
 %
Operating expenses

 

 

 

Lease operating
9,264

 
10,787

 
1,523

 
14
 %
Gathering, processing and transportation
4,391

 
4,281

 
(110
)
 
(3
)%
Production and ad valorem taxes
(254
)
 
2,834

 
3,088

 
109
 %
General and administrative
11,747

 
12,954

 
1,207

 
9
 %
Exploration
9,384

 
19,368

 
9,984

 
52
 %
Depreciation, depletion and amortization
51,740

 
33,036

 
(18,704
)
 
(57
)%
Impairments
28,616

 
71,071

 
42,455

 
60
 %
Total operating expenses
114,888

 
154,331

 
39,443

 
26
 %
Operating loss
(38,043
)
 
(80,713
)
 
42,670

 
53
 %
Other income (expense)

 

 

 

Interest expense
(15,084
)
 
(14,143
)
 
(941
)
 
(7
)%
Loss on extinguishment of debt
—

 
(24,238
)
 
24,238

 
NM

Derivatives
43,826

 
7,001

 
36,825

 
NM

Other
28

 
129

 
(101
)
 
(78
)%
Loss before income taxes
(9,273
)
 
(111,964
)
 
102,691

 
92
 %
Income tax benefit
3,635

 
40,046

 
(36,411
)
 
(91
)%
Net loss
$
(5,638
)
 
$
(71,918
)
 
$
66,280

 
92
 %
NM - Not meaningful
 
 
 
 
 
 
 
 



21

Production
 
The following tables set forth a summary of our total and daily production volumes by product and geographical region for the periods presented:
Natural gas
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
 (MMcf)
 
 
 
 (MMcf per day)
 
 
 
 
Texas
1,789

 
2,787

 
(998
)
 
19.7

 
30.6

 
(10.9
)
 
(36
)%
Appalachia
1,952

 
2,256

 
(303
)
 
21.5

 
24.8

 
(3.3
)
 
(13
)%
Mid-Continent
841

 
2,161

 
(1,320
)
 
9.2

 
23.7

 
(14.5
)
 
(61
)%
Mississippi
1,276

 
1,665

 
(388
)
 
14.0

 
18.3

 
(4.3
)
 
(23
)%
 
5,859

 
8,869

 
(3,010
)
 
64.4

 
97.4

 
(33
)
 
(34
)%
 
Crude oil
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MBbl)
 
(MBbl per day)
 
 
 
 
Texas
518.3

 
120.1

 
398.2

 
5.70

 
1.32

 
4.38

 
332
 %
Appalachia
0.3

 
(0.7
)
 
1.0

 
—

 
(0.01
)
 
0.01

 
100
 %
Mid-Continent
49.2

 
94.0

 
(44.8
)
 
0.54

 
1.03

 
(0.49
)
 
(48
)%
Mississippi
3.8

 
5.4

 
(1.6
)
 
0.04

 
0.06

 
(0.02
)
 
(33
)%
 
571.6

 
218.8

 
352.8

 
6.28

 
2.40

 
3.88

 
162
 %
 
NGLs
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MBbl)
 
(MBbl per day)
 
 
 
 
Texas
118.1

 
119.4

 
(1.3
)
 
1.30

 
1.31

 
(0.01
)
 
(1
)%
Appalachia
0.2

 
(0.1
)
 
0.3

 
—

 
—

 
—

 
NM

Mid-Continent
109.1

 
133.6

 
(24.5
)
 
1.20

 
1.47

 
(0.27
)
 
(18
)%
 
227.4

 
252.9

 
(25.5
)
 
2.50

 
2.78

 
(0.28
)
 
(10
)%
 
Combined total
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MMcfe)
 
(MMcfe per day)
 
 
 
 
Texas
5,608

 
4,224

 
1,384

 
61.6

 
46.4

 
15.2

 
33
 %
Appalachia
1,955

 
2,251

 
(296
)
 
21.5

 
24.7

 
(3.2
)
 
(13
)%
Mid-Continent
1,790

 
3,527

 
(1,736
)
 
19.7

 
38.8

 
(19.1
)
 
(49
)%
Mississippi
1,299

 
1,697

 
(398
)
 
14.3

 
18.6

 
(4.3
)
 
(23
)%
 
10,653

 
11,699

 
(1,046
)
 
117.1

 
128.5

 
(11.4
)
 
(9
)%
Certain results in the tables above may not calculate due to rounding.
 
 
 
 
 
 
 
 
 
The decline in total production during the quarter ended June 30, 2012 compared to the corresponding quarter of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Arkoma Basin properties in August 2011. The effect of the sale of the Arkoma Basin properties was approximately 0.6 Bcfe during the quarter. The natural declines in production were partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 45% of total production on an equivalent basis in the quarter ended June 30, 2012 was attributable to oil and NGLs, a 69% increase over the prior year quarter. The shift in production mix reflects our focus on emerging oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the quarter ended June 30, 2012, our Eagle Ford Shale production of 3.6 Bcfe represented 34% of our total production. We had approximately 0.5 Bcfe of production from this play during the 2011 quarter.


22

Product Revenues and Prices
 
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographical region for the periods presented:
 
Natural gas
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 
 
 ($ per Mcf)
 
 
Texas
$
3,254

 
$
13,126

 
$
(9,872
)
 
$
1.82

 
$
4.71

 
$
(2.89
)
Appalachia
3,962

 
9,812

 
(5,850
)
 
2.03

 
4.35

 
(2.32
)
Mid-Continent
200

 
7,851

 
(7,651
)
 
0.24

 
3.63

 
(3.39
)
Mississippi
2,887

 
7,511

 
(4,624
)
 
2.26

 
4.51

 
(2.25
)
 
$
10,303

 
$
38,300

 
$
(27,997
)
 
$
1.76

 
$
4.32

 
$
(2.56
)
 
Crude oil
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
($ per Bbl)
 
 
Texas
$
53,806

 
$
11,568

 
$
42,238

 
$
103.81

 
$
96.32

 
$
7.49

Appalachia
27

 
(42
)
 
69

 
90.00

 
60.00

 
30.00

Mid-Continent
4,164

 
9,445

 
(5,281
)
 
84.63

 
100.48

 
(15.85
)
Mississippi
385

 
577

 
(192
)
 
101.32

 
106.85

 
(5.53
)
 
$
58,382

 
$
21,548

 
$
36,834

 
$
102.14

 
$
98.48

 
$
3.66

 
NGLs
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
($ per Bbl)
 
 
Texas
$
3,805

 
$
6,166

 
$
(2,361
)
 
$
32.22

 
$
51.64

 
$
(19.42
)
Appalachia
10

 
(1
)
 
11

 
50.00

 
10.00

 
40.00

Mid-Continent
3,741

 
6,996

 
(3,255
)
 
34.29

 
52.37

 
(18.08
)
 
$
7,556

 
$
13,161

 
$
(5,605
)
 
$
33.23

 
$
52.04

 
$
(18.81
)
 
Combined total
Three Months Ended June 30,
 
Favorable
 
Three Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 ($ per Mcfe)
 
 
Texas
$
60,865

 
$
30,860

 
$
30,005

 
$
10.85

 
$
7.31

 
$
3.54

Appalachia
3,999

 
9,769

 
(5,770
)
 
2.05

 
4.34

 
(2.29
)
Mid-Continent
8,105

 
24,292

 
(16,187
)
 
4.53

 
6.89

 
(2.36
)
Mississippi
3,272

 
8,088

 
(4,816
)
 
2.52

 
4.77

 
(2.25
)
 
$
76,241

 
$
73,009

 
$
3,232

 
$
7.16

 
$
6.24

 
$
0.92

 
As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $1.5 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from other partners in our Mid-Continent region. The following table provides an analysis of the change in our revenues for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011:
 
 Revenue Variance Due to
 
 Volume
 
 Price
 
 Total
Natural gas
$
(12,998
)
 
$
(14,999
)
 
$
(27,997
)
Crude oil
34,724

 
2,110

 
36,834

NGLs
(1,326
)
 
(4,279
)
 
(5,605
)
 
$
20,400

 
$
(17,168
)
 
$
3,232



23

Effects of Derivatives
 
Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge natural gas and crude oil prices. During the three months ended June 30, 2012 and 2011, we received $5.6 million and $4.1 million in net cash settlements from oil and gas derivatives.
 
The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Natural gas revenues as reported
$
10,303

 
$
38,300

 
$
(27,997
)
 
(73
)%
Cash settlements on natural gas derivatives, net
5,630

 
4,261

 
1,369

 
32
 %
Natural gas revenues adjusted for derivatives
$
15,933

 
$
42,561

 
$
(26,628
)
 
(63
)%
Natural gas prices per Mcf, as reported
$
1.76

 
$
4.32

 
$
(2.56
)
 
(59
)%
Cash settlements on natural gas derivatives per Mcf
0.96

 
0.48

 
0.48

 
100
 %
Natural gas prices per Mcf adjusted for derivatives
$
2.72

 
$
4.80

 
$
(2.08
)
 
(43
)%
Crude oil revenues as reported
$
58,382

 
$
21,548

 
$
36,834

 
171
 %
Cash settlements on crude oil derivatives, net
(65
)
 
(128
)
 
63

 
49
 %
Crude oil revenues adjusted for derivatives
$
58,317

 
$
21,420

 
$
36,897

 
172
 %
Crude oil prices per Bbl, as reported
$
102.14

 
$
98.48

 
$
3.66

 
4
 %
Cash settlements on crude oil derivatives per Bbl
(0.11
)
 
(0.59
)
 
0.48

 
81
 %
Crude oil prices per Bbl adjusted for derivatives
$
102.03

 
$
97.89

 
$
4.14

 
4
 %
 
Gain on Sales of Property and Equipment
 
We recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.
 
Other Income
 
Other income decreased during the quarter ended June 30, 2012 due primarily to lower gathering, transportation, compression and salt water disposal fees.
 
Operating Expenses
 
As discussed individually below, we experienced an absolute decrease in several operating expenses. Due primarily to declining natural gas production, however, certain expenses increased on a unit of production basis. The following table summarizes certain of our operating expenses per Mcfe for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Lease operating
$
0.87

 
$
0.92

 
$
0.05

 
5
 %
Gathering, processing and transportation
0.41

 
0.37

 
(0.04
)
 
(11
)%
Production and ad valorem taxes
(0.02
)
 
0.24

 
0.26

 
108
 %
General and administrative excluding share-based compensation and restructuring charges
0.94

 
0.93

 
(0.01
)
 
(1
)%
General and administrative
1.10

 
1.11

 
0.01

 
1
 %
Depreciation, depletion and amortization
4.86

 
2.82

 
(2.04
)
 
(72
)%
 

24

Lease Operating
 
Lease operating expense decreased on an absolute basis and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs. Certain expense decreases were also attributable to the sale of our Arkoma Basin properties. Cost decreases were partially offset by higher utility, field contracting, well tending, chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.
 
Gathering, Processing and Transportation
 
Gathering, processing and transportation charges increased slightly during the 2012 period, despite lower overall product volume, due primarily to a higher amount of unrecovered firm transportation costs in the Appalachian region.
 
Production and Ad Valorem Taxes
 
Production and ad valorem taxes decreased during the 2012 period due primarily to recently approved Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells for the period of July 1, 2009 through June 30, 2011. Rebates were also recognized for certain Texas wells. Production taxes also decreased due to lower natural gas volume and prices in the 2012 period as compared to the 2011 period.
 
General and Administrative
 
The following table sets forth the components of general and administrative expenses for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Recurring general and administrative expenses
$
10,006

 
$
10,889

 
$
883

 
8
%
Share-based compensation (liability-classified)
553

 
—

 
(553
)
 
NM

Share-based compensation (equity-classified)
1,336

 
2,013

 
677

 
34
%
Restructuring expenses
(148
)
 
52

 
200

 
NM

 
$
11,747

 
$
12,954

 
$
1,207

 
9
%
 
Recurring general and administrative expenses decreased due to reduced headcount and lower support costs primarily attributable to restructuring actions taken during 2011. Liability-classified share-based compensation is attributable to our performance-based restricted stock unit awards, which are payable in cash upon achievement of certain market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the 2012 period due primarily to a lower number of awards granted. Restructuring expenses include an adjustment to the lease obligation for our former Tulsa, Oklahoma office due to a change in estimated sub-lease rental income.
 
Exploration
 
The following table sets forth the components of exploration expenses for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Unproved leasehold amortization
$
8,284

 
$
11,966

 
$
3,682

 
31
%
Dry hole costs
—

 
2,116

 
2,116

 
100
%
Geological and geophysical costs
781

 
4,302

 
3,521

 
82
%
Other, primarily delay rentals
319

 
984

 
665

 
68
%
 
$
9,384

 
$
19,368

 
$
9,984

 
52
%
 
Unproved leasehold amortization declined during the 2012 period as certain properties primarily in the Eagle Ford Shale were transferred to proved in the second half of 2011 and the first half of 2012. The prior year period included dry hole costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, geological and geophysical and other

25

exploration costs decreased during the 2012 period as our efforts are concentrated on the Eagle Ford Shale while the prior year period included multiple exploratory prospect activities.

Depreciation, Depletion and Amortization (DD&A)
 
The following tables set forth the components of DD&A and the nature of the variances for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Depletion
$
50,262

 
$
31,606

 
$
(18,656
)
 
(59
)%
Depreciation - Oil and gas operations
997

 
619

 
(378
)
 
(61
)%
Depreciation - Corporate
367

 
679

 
312

 
46
 %
Amortization
114

 
132

 
18

 
14
 %
 
$
51,740

 
$
33,036

 
$
(18,704
)
 
(57
)%
 
 
 DD&A Variance Due to
 
 Production
 
 Rates
 
 Total
Three months ended June 30, 2012 compared to 2011
$
2,955

 
$
(21,659
)
 
$
(18,704
)

The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $4.72 per Mcfe for the 2012 period from $2.70 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Impairments

The following table summarizes the impairments recorded for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Oil and gas properties
$
28,481

 
$
71,071

 
$
42,590

 
60
%
Other
135

 
—

 
(135
)
 
NM

 
$
28,616

 
$
71,071

 
$
42,455

 
60
%
 
During the quarter ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the quarter ended ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

Interest Expense
 
The following table summarizes the components of our total interest expense for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Interest on borrowings and related fees
$
14,289

 
$
13,120

 
$
(1,169
)
 
(9
)%
Accretion of original issue discount
341

 
583

 
242

 
42
 %
Amortization of debt issuance costs
694

 
895

 
201

 
22
 %
Capitalized interest
(240
)
 
(455
)
 
(215
)
 
(47
)%
 
$
15,084

 
$
14,143

 
$
(941
)
 
(7
)%
 
The issuance of the 7.25% Senior Notes due 2019, or 2019 Senior Notes, and borrowings under the Revolver, offset by

26

the repurchase of approximately 98% of the outstanding 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes, with an effective interest rate of 8.5%, resulted in an approximate $184 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental fees paid in cash.

Derivatives
 
The following table summarizes the components of our derivative income for the periods presented:
 
Three Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Oil and gas derivative unrealized gain
$
36,257

 
$
1,864

 
$
34,393

 
NM

Oil and gas derivative realized gain
5,564

 
4,133

 
1,431

 
35
%
Interest rate swap unrealized gain
599

 
106

 
493

 
NM

Interest rate swap realized gain
1,406

 
898

 
508

 
57
%
 
$
43,826

 
$
7,001

 
$
36,825

 
NM

 
We received cash settlements of $7.0 million during the quarter ended June 30, 2012 and $5.0 million during the comparable period in 2011. Cash settlements in the 2012 period included $1.2 million in connection with the termination of our interest rate swap agreement. The significant increase in the unrealized gain on commodity derivatives was due primarily to oil prices declining below our hedged prices.

Other Income
 
Other income decreased during the 2012 period due primarily to lower interest income earned on average cash balances.
 
Income Tax Expense
 
The effective tax rate for the three months ended June 30, 2012 was 39.2% compared to 35.8% for the 2011 period. Due to operating losses incurred, we recognized income tax benefits during both periods.

27

Results of Operations
 
Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011
 
The following table sets forth a summary of certain operating and financial performance for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Total Production:
 
 
 
 
 
 
 
  Natural gas (MMcf)
12,153

 
18,594

 
(6,441
)
 
(35
)%
  Crude oil (MBbl)
1,120

 
407

 
713

 
175
 %
  NGLs (MBbl)
442

 
473

 
(31
)
 
(7
)%
     Total production (MMcfe)
21,527

 
23,870

 
(2,343
)
 
(10
)%
Realized prices, before derivatives:
 
 
 
 
 
 
 
  Natural gas ($/Mcf)
$
2.07

 
$
4.27

 
$
(2.20
)
 
(52
)%
  Crude oil ($/Bbl)
104.55

 
93.80

 
10.75

 
11
 %
  NGLs ($/Bbl)
37.60

 
48.82

 
(11.22
)
 
(23
)%
     Total ($/Mcfe)
$
7.38

 
$
5.89

 
$
1.49

 
25
 %
Revenues
 
 
 
 
 
 
 
Natural gas
$
25,189

 
$
79,489

 
(54,300
)
 
(68
)%
Crude oil
117,105

 
38,131

 
78,974

 
207
 %
Natural gas liquids (NGLs)
16,627

 
23,082

 
(6,455
)
 
(28
)%
Total product revenues
158,921

 
140,702

 
18,219

 
13
 %
Gain on sales of property and equipment, net
834

 
452

 
382

 
85
 %
Other
1,501

 
1,047

 
454

 
43
 %
Total revenues
161,256

 
142,201

 
19,055

 
13
 %
Operating expenses
 
 
 
 
 
 
 
Lease operating
18,407

 
21,064

 
2,657

 
13
 %
Gathering, processing and transportation
8,545

 
8,309

 
(236
)
 
(3
)%
Production and ad valorem taxes
3,326

 
7,898

 
4,572

 
58
 %
General and administrative
23,888

 
26,306

 
2,418

 
9
 %
Exploration
17,382

 
48,916

 
31,534

 
64
 %
Depreciation, depletion and amortization
102,557

 
67,879

 
(34,678
)
 
(51
)%
Impairments
28,616

 
71,071

 
42,455

 
60
 %
Total operating expenses
202,721

 
251,443

 
48,722

 
19
 %
Operating loss
(41,465
)
 
(109,242
)
 
67,777

 
62
 %
Other income (expense)
 
 
 
 
 
 
 
Interest expense
(29,858
)
 
(27,627
)
 
(2,231
)
 
(8
)%
Loss on extinguishment of debt
—

 
(24,238
)
 
24,238

 
NM

Derivatives
43,521

 
8,329

 
35,192

 
NM

Other
29

 
273

 
(244
)
 
(89
)%
Loss before income taxes
(27,773
)
 
(152,505
)
 
124,732

 
82
 %
Income tax benefit
10,236

 
54,247

 
(44,011
)
 
(81
)%
Net loss
$
(17,537
)
 
$
(98,258
)
 
$
80,721

 
82
 %
NM - Not meaningful
 
 
 
 
 
 
 


28

Production
 
The following tables set forth a summary of our total and daily production volumes by product and geographical region for the periods presented:
Natural gas
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
 (MMcf)
 
 
 
 (MMcf per day)
 
 
 
 
Texas
3,620

 
5,553

 
(1,934
)
 
19.9

 
30.7

 
(10.8
)
 
(35
)%
Appalachia
4,014

 
4,616

 
(601
)
 
22.1

 
25.5

 
(3.4
)
 
(13
)%
Mid-Continent
1,949

 
4,932

 
(2,983
)
 
10.7

 
27.2

 
(16.5
)
 
(61
)%
Mississippi
2,570

 
3,494

 
(924
)
 
14.1

 
19.3

 
(5.2
)
 
(27
)%
 
12,153

 
18,594

 
(6,441
)
 
66.8

 
102.7

 
(35.9
)
 
(35
)%
 
Crude oil
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MBbl)
 
(MBbl per day)
 
 
 
 
Texas
997.5

 
177.1

 
820.5

 
5.48

 
0.98

 
4.50

 
459
 %
Appalachia
0.5

 
(0.2
)
 
0.7

 
—

 
—

 
—

 
NM

Mid-Continent
114.3

 
219.1

 
(104.8
)
 
0.63

 
1.21

 
(0.58
)
 
(48
)%
Mississippi
7.8

 
10.6

 
(2.8
)
 
0.04

 
0.06

 
(0.02
)
 
(33
)%
 
1,120.1

 
406.5

 
713.6

 
6.15

 
2.25

 
3.90

 
173
 %
 
NGLs
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MBbl)
 
(MBbl per day)
 
 
 
 
Texas
224.5

 
239.0

 
(14.6
)
 
1.23

 
1.32

 
(0.09
)
 
(7
)%
Appalachia
0.4

 
0.1

 
0.3

 
—

 
—

 
—

 
NM

Mid-Continent
217.3

 
233.6

 
(16.3
)
 
1.19

 
1.29

 
(0.10
)
 
(8
)%
 
442.2

 
472.8

 
(30.6
)
 
2.42

 
2.61

 
(0.19
)
 
(7
)%
 
Combined total
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
% Change
 
(MMcfe)
 
(MMcfe per day)
 
 
 
 
Texas
10,952

 
8,050

 
2,902

 
60.2

 
44.5

 
15.7

 
35
 %
Appalachia
4,020

 
4,615

 
(595
)
 
22.1

 
25.5

 
(3.4
)
 
(13
)%
Mid-Continent
3,939

 
7,648

 
(3,710
)
 
21.6

 
42.3

 
(20.7
)
 
(49
)%
Mississippi
2,617

 
3,557

 
(940
)
 
14.4

 
19.7

 
(5.3
)
 
(27
)%
 
21,527

 
23,870

 
(2,343
)
 
118.3

 
132.0

 
(13.7
)
 
(10
)%
Certain results in the tables above may not calculate due to rounding.
 
 
 
 
 
 
 
 
 
The decline in total production during the six months ended June 30, 2012 compared to the corresponding period of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Arkoma Basin properties in August 2011. The effect of the sale of the Arkoma Basin properties was approximately 1.6 Bcfe during the six month period. The natural declines in production were otherwise essentially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 44% of total production on an equivalent basis in the six months ended June 30, 2012 was attributable to oil and NGLs, a 76% increase over the prior year period. The shift in production mix reflects our focus on emerging oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the six months ended June 30, 2012, our Eagle Ford Shale production of 6.7 Bcfe represented 31% of our total production. We had approximately 0.7 Bcfe of production from this play during the first half of 2011.


29

Product Revenues and Prices
 
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographical region for the periods presented:
 
Natural gas
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 
 
 
 
 ($ per Mcf)
 
 
Texas
$
7,487

 
$
23,764

 
$
(16,277
)
 
$
2.07

 
$
4.28

 
$
(2.21
)
Appalachia
9,385

 
19,588

 
(10,203
)
 
2.34

 
4.24

 
(1.90
)
Mid-Continent
1,735

 
20,914

 
(19,179
)
 
0.89

 
4.24

 
(3.35
)
Mississippi
6,582

 
15,223

 
(8,641
)
 
2.56

 
4.36

 
(1.80
)
 
$
25,189

 
$
79,489

 
$
(54,300
)
 
$
2.07

 
$
4.27

 
$
(2.20
)
 
Crude oil
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 
 
 
 
 ($ per Bbl)
 
 
Texas
$
105,595

 
$
16,644

 
$
88,951

 
$
105.86

 
$
93.99

 
$
11.87

Appalachia
49

 
(8
)
 
57

 
93.16

 
36.04

 
57.12

Mid-Continent
10,628

 
20,430

 
(9,802
)
 
93.02

 
93.25

 
(0.23
)
Mississippi
833

 
1,065

 
(232
)
 
106.55

 
100.74

 
5.81

 
$
117,105

 
$
38,131

 
$
78,974

 
$
104.55

 
$
93.80

 
$
10.75

 
NGLs
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 
 
 
 
 
 
 
 
 
Texas
$
8,580

 
$
11,518

 
$
(2,938
)
 
$
38.23

 
$
48.18

 
$
(9.95
)
Appalachia
21

 
9

 
12

 
52.63

 
69.23

 
(16.60
)
Mid-Continent
8,026

 
11,555

 
(3,529
)
 
36.93

 
49.46

 
(12.53
)
 
$
16,627

 
$
23,082

 
$
(6,455
)
 
$
37.60

 
$
48.82

 
$
(11.22
)
 
Combined total
Six Months Ended June 30,
 
Favorable
 
Six Months Ended June 30,
 
Favorable
 
2012
 
2011
 
(Unfavorable)
 
2012
 
2011
 
(Unfavorable)
 
 
 
 
 
 
 
 
 
 
 
 
Texas
$
121,662

 
$
51,926

 
$
69,736

 
$
11.11

 
$
6.45

 
$
4.66

Appalachia
9,455

 
19,589

 
(10,134
)
 
2.35

 
4.24

 
(1.89
)
Mid-Continent
20,389

 
52,899

 
(32,510
)
 
5.18

 
6.92

 
(1.74
)
Mississippi
7,415

 
16,288

 
(8,873
)
 
2.83

 
4.58

 
(1.75
)
 
$
158,921

 
$
140,702

 
$
18,219

 
$
7.38

 
$
5.89

 
$
1.49

 
As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $2.3 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from other partners in our Mid-Continent region. The following table provides an analysis of the change in our revenues for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011:
 
Revenue Variance Due to
 
Volume
 
Price
 
Total
Natural gas
$
(27,535
)
 
$
(26,765
)
 
$
(54,300
)
Crude oil
66,936

 
12,038

 
78,974

NGLs
(1,495
)
 
(4,960
)
 
(6,455
)
 
$
37,906

 
$
(19,687
)
 
$
18,219



30

Effects of Derivatives
 
Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge natural gas and crude oil prices. During the six months ended June 30, 2012 and 2011, we received $13.5 million and $10.9 million in net cash settlements from oil and gas derivatives.
 
The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Natural gas revenues as reported
$
25,189

 
$
79,489

 
$
(54,300
)
 
(68
)%
Cash settlements on natural gas derivatives, net
13,718

 
11,230

 
2,488

 
22
 %
Natural gas revenues adjusted for derivatives
$
38,907

 
$
90,719

 
$
(51,812
)
 
(57
)%
Natural gas prices per Mcf, as reported
$
2.07

 
$
4.27

 
$
(2.20
)
 
(52
)%
Cash settlements on natural gas derivatives per Mcf
1.13

 
0.60

 
0.53

 
88
 %
Natural gas prices per Mcf adjusted for derivatives
$
3.20

 
$
4.87

 
$
(1.67
)
 
(34
)%
Crude oil revenues as reported
$
117,105

 
$
38,131

 
$
78,974

 
207
 %
Cash settlements on crude oil derivatives, net
(172
)
 
(353
)
 
181

 
51
 %
Crude oil revenues adjusted for derivatives
$
116,933

 
$
37,778

 
$
79,155

 
210
 %
Crude oil prices per Bbl, as reported
$
104.55

 
$
93.80

 
$
10.75

 
11
 %
Cash settlements on crude oil derivatives per Bbl
(0.15
)
 
(0.87
)
 
0.72

 
83
 %
Crude oil prices per Bbl adjusted for derivatives
$
104.40

 
$
92.93

 
$
11.47

 
12
 %
 
Gain on Sales of Property and Equipment
 
In January 2012, we sold our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania for proceeds of $1.0 million, net of transaction costs. We recognized a gain of $0.6 million in connection with this transaction. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.
 
Other Income
 
Other income increased during the six months ended June 30, 2012 due primarily to higher gathering, transportation and compression fees.
 
Operating Expenses
 
As discussed individually below, we experienced an absolute decrease in several operating expenses. Due primarily to declining natural gas production, however, certain expenses increased on a unit of production basis. The following table summarizes certain of our operating expenses per Mcfe for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Lease operating
$
0.86

 
$
0.88

 
$
0.02

 
2
 %
Gathering, processing and transportation
0.40

 
0.35

 
(0.05
)
 
(14
)%
Production and ad valorem taxes
0.15

 
0.33

 
0.18

 
55
 %
General and administrative excluding share-based compensation and restructuring charges
0.95

 
0.94

 
(0.01
)
 
(1
)%
General and administrative
1.11

 
1.10

 
(0.01
)
 
(1
)%
Depreciation, depletion and amortization
4.76

 
2.84

 
(1.92
)
 
(68
)%

31

Lease Operating
 
Lease operating expense decreased on an absolute and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs. Certain expense decreases were also attributable to the sale of our Arkoma Basin properties. Cost decreases were partially offset by higher field contracting, well tending, water disposal, chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.
 
Gathering, Processing and Transportation
 
Gathering, processing and transportation charges increased slightly during the 2012 period, despite lower overall product volume, due primarily to a higher amount of unrecovered firm transportation costs in the Appalachian region.
 
Production and Ad Valorem Taxes
 
Production and ad valorem taxes decreased during the 2012 period due primarily to recently approved Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells for the period of July 1, 2009 through June 30, 2011. Rebates were also recognized for certain Texas wells. Production taxes also decreased due to lower natural gas volume and prices in the 2012 period as compared to the 2011 period. As a percentage of product revenue, production and ad valorem taxes decreased to 2.0% during the 2012 period from 5.6% during the 2011 period.
 
General and Administrative
 
The following table sets forth the components of general and administrative expenses for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Recurring general and administrative expenses
$
20,460

 
$
22,427

 
$
1,967

 
9
%
Share-based compensation (liability-classified)
625

 
—

 
(625
)
 
NM

Share-based compensation (equity-classified)
2,951

 
3,809

 
858

 
23
%
Restructuring expenses
(148
)
 
70

 
218

 
NM

 
$
23,888

 
$
26,306

 
$
2,418

 
9
%
 
Recurring general and administrative expenses decreased due to reduced headcount and lower support costs primarily attributable to restructuring actions taken during 2011. Liability-classified share-based compensation is attributable to our performance-based restricted stock unit awards, which are payable in cash upon achievement of certain market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the 2012 period due primarily to a lower number of awards granted. Restructuring expenses include an adjustment to the lease obligation for our former Tulsa, Oklahoma office due to a change in estimated sub-lease rental income.
 
Exploration
 
The following table sets forth the components of exploration expenses for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Unproved leasehold amortization
$
16,455

 
$
22,557

 
$
6,102

 
27
%
Dry hole costs
—

 
18,524

 
18,524

 
100
%
Geological and geophysical costs
358

 
6,137

 
5,779

 
94
%
Other, primarily delay rentals
569

 
1,698

 
1,129

 
66
%
 
$
17,382

 
$
48,916

 
$
31,534

 
64
%
 
Unproved leasehold amortization declined during the 2012 period as certain properties in the Eagle Ford and Marcellus Shales were transferred to proved in the second half of 2011 and the first half of 2012. The prior year period included dry hole

32

costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, geological and geophysical and other exploration costs decreased during the 2012 period as our efforts are concentrated on the Eagle Ford Shale while the prior year period included multiple exploratory prospect activities.

Depreciation, Depletion and Amortization (DD&A)
 
The following tables set forth the components of DD&A and the nature of the variances for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Depletion
$
99,973

 
$
65,049

 
$
(34,924
)
 
(54
)%
Depreciation - Oil and gas operations
1,575

 
1,237

 
(338
)
 
(27
)%
Depreciation - Corporate
780

 
1,331

 
551

 
41
 %
Amortization
229

 
262

 
33

 
13
 %
 
$
102,557

 
$
67,879

 
$
(34,678
)
 
(51
)%
 
 
 DD&A Variance Due to
 
 Production
 
 Rates
 
 Total
Three months ended June 30, 2012 compared to 2011
$
6,663

 
$
(41,341
)
 
$
(34,678
)
 
The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $4.64 per Mcfe for the 2012 period from $2.72 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Impairments

The following table summarizes the impairments recorded for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Oil and gas properties
$
28,481

 
$
71,071

 
$
42,590

 
60
%
Other
135

 
—

 
(135
)
 
NM

 
$
28,616

 
$
71,071

 
$
42,455

 
60
%

During the six months ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the six months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

Interest Expense
 
The following table summarizes the components of our total interest expense for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Interest on borrowings and related fees
$
28,306

 
$
23,867

 
$
(4,439
)
 
(19
)%
Accretion of original issue discount
674

 
2,788

 
2,114

 
76
 %
Amortization of debt issuance costs
1,376

 
1,962

 
586

 
30
 %
Capitalized interest
(498
)
 
(990
)
 
(492
)
 
(50
)%
 
$
29,858

 
$
27,627

 
$
(2,231
)
 
(8
)%
 

33

The issuance of the 2019 Senior Notes and borrowings under the Revolver, offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate of 8.5%, resulted in an approximate $184 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental fees paid in cash.

Derivatives
 
The following table summarizes the components of our derivative (loss) income for the periods presented:
 
Six Months Ended June 30,
 
Favorable
 
 
 
2012
 
2011
 
(Unfavorable)
 
% Change
Oil and gas derivative unrealized gain (loss)
$
28,570

 
$
(3,572
)
 
$
32,142

 
NM

Oil and gas derivative realized gain
13,545

 
10,877

 
2,668

 
25
%
Interest rate swap unrealized gain
—

 
126

 
(126
)
 
NM

Interest rate swap realized gain
1,406

 
898

 
508

 
57
%
 
$
43,521

 
$
8,329

 
$
35,192

 
NM

 
We received cash settlements of $15.0 million during the six months ended June 30, 2012 and $11.8 million during the comparable period in 2011. The cash settlements in the 2012 period included $1.2 million in connection with the termination of our interest rate swap agreement. The significant increase in the unrealized gain on commodity derivatives was due primarily oil prices declining below our hedged prices.
 
Other
 
Other income decreased during the 2012 period due primarily to lower interest income earned on average cash balances.
 
Income Tax Expense
 
The effective tax rate for the six months ended June 30, 2012 was 36.9% compared to 35.6% for the 2011 period. Due to operating losses incurred, we recognized income tax benefits during both periods.

34


Liquidity and Capital Resources
 
Sources of Liquidity
 
We are currently meeting our cash requirements with a combination of operating cash flows, borrowings under the Revolver and proceeds from sales of assets. We have no material debt maturities until 2016. Our 2012 business strategy requires capital expenditures in excess of our operating cash flows. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our capital program for the remainder of 2012 with operating cash flows and borrowings under the Revolver. We recently discontinued our common stock dividend which improves liquidity by increasing available cash flows by approximately $10 million per year. Other potential sources of additional liquidity include an increase in our Revolver borrowing base resulting from an increase in our Eagle Ford Shale proved reserves, third party joint ventures, additional non-strategic asset sales or securities offerings. There can be no assurance, however, that any such actions will be successful.
 
In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver has a borrowing base that is redetermined semi-annually. In connection with the closing of the Appalachian asset sale transaction on July 31, 2012, the borrowing base under the Revolver was decreased by $70 million to a level of $230 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. Our current business plans anticipate us borrowing amounts under the Revolver that are within the borrowing base limitations.
 
As of August 1, 2012, after repaying a portion of our outstanding Revolver balance with proceeds from the sale of our Appalachian assets, we had approximately $11 million of cash on hand and $128.3 million of unused borrowing capacity under the Revolver. The borrowing capacity is determined by reducing the borrowing base commitment of $230 million by remaining outstanding borrowings of $100 million and outstanding letters of credit of $1.7 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 June 30,
$
156,033

 
$
180,000

 
2.1547
%
Six Months Ended June 30,
$
132,758

 
$
180,000

 
2.1049
%
 
Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, we actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. During the first half of 2012, our commodity derivatives portfolio provided $13.7 million of cash inflows related to lower than anticipated prices received for our natural gas production and $0.2 million of cash outflows attributable to higher than anticipated prices received for our crude oil production.
 
In January 2012, we amended the Revolver to enhance our ability to hedge production. Previously, our hedging was limited to the lesser of certain fixed percentages of our reasonably anticipated production from proved developed reserves and total proved reserves. The amendment expands the potential volume subject to hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves.
 
For the remainder of 2012, we have hedged approximately 32% of our estimated natural gas production, at a weighted average swap price of $5.24 per MMBtu. In addition, we have hedged approximately 67% of our estimated crude oil production for the remainder of 2012, at weighted average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel.
 

35

Cash Flows
 
The following table summarizes our statements of cash flows for the periods presented:
 
Six Months Ended June 30,
 
 
 
2012
 
2011
 
Variance
Cash flows from operating activities
$
115,725

 
$
63,759

 
$
51,966

Cash flows from investing activities
 

 
 

 
 

Capital expenditures -  property and equipment
(188,236
)
 
(211,081
)
 
22,845

Proceeds from sales of property and equipment and other, net
707

 
796

 
(89
)
Net cash used in investing activities
(187,529
)
 
(210,285
)
 
22,756

Cash flows from financing activities
 

 
 

 
 

Dividends paid
(5,176
)
 
(5,156
)
 
(20
)
Proceeds from revolving credit facility borrowings, net
81,000

 
—

 
81,000

Proceeds from issuance of senior notes
—

 
300,000

 
(300,000
)
Repurchase of Convertible Notes
—

 
(232,963
)
 
232,963

Debt issuance costs paid
—

 
(6,559
)
 
6,559

Other, net
—

 
974

 
(974
)
Net cash provided by (used in) financing activities
75,824

 
56,296

 
19,528

Net decrease in cash and cash equivalents
$
4,020

 
$
(90,230
)
 
$
94,250

 
 
Cash Flows From Operating Activities
 
The following table summarizes the most significant variances in our cash flows from operating activities:
Cash flows from operating activities for the six months ended June 30, 2011
 
 
 
 
$
63,759

Variances due to:
 
 
 
 
 
Effect of higher operating margins, net of working capital changes
 
 
 
 
53,618

Higher settlements from commodity derivatives portfolio
 
 
 
 
2,668

Transaction costs paid in connection with extinguishment of debt in 2011
 
 
 
 
2,416

Higher interest payments, net of interest rate swap settlements
 
 
 
 
(6,951
)
Other, net
 
 
 
 
215

Cash flows from operating activities for the six months ended June 30, 2012
 
 
 
 
$
115,725

 
Due primarily to the realization of higher net margins on our expanding crude oil production, our cash flows from operating activities improved significantly during the 2012 period as compared to the 2011 period. During the 2012 period, we realized higher settlements from our commodity derivatives portfolio as compared to the 2011 period due primarily to lower natural gas prices partially offset by a lower overall hedged production volume. We paid higher amounts for interest during the 2012 period due to higher average outstanding debt balances. In addition, our sources from working capital were higher during the 2012 period due primarily to timing of collections and disbursements and lower compensation-related costs paid in the 2012 period. The 2011 period included transaction costs paid in connection with the repurchase of our Convertible Notes.
  
Cash Flows From Investing Activities
 
Capital expenditures were lower during the 2012 period due primarily to our focus on Eagle Ford Shale drilling. During the prior year period, we acquired significant acreage in the Eagle Ford Shale and had a more extensive capital program in the Mid-Continent region.
 
Proceeds from sales of non-core properties and other assets were received during both the 2012 and 2011 periods. The amounts received during the 2012 period are primarily attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania. Both periods include the receipt of insurance proceeds attributable to damages from a fire at one of our warehouse facilities in early 2011.

36

The following table sets forth costs related to our capital expenditures programs for the periods presented:
 
 
 
Six Months Ended June 30,
 
 
 
2012
 
2011
Oil and gas:
 
 
 
 
 
Development drilling
 
 
$
120,304

 
$
119,711

Exploration drilling
 
 
42,056

 
39,765

Seismic
 
 
320

 
6,137

Lease acquisitions, field projects and other
 
 
10,894

 
39,901

Pipeline and gathering facilities
 
 
8,349

 
3,571

 
 
 
181,923

 
209,085

Other - Corporate
 
 
426

 
629

 
 
 
$
182,349

 
$
209,714

 
The following table reconciles the total costs of our capital expenditures programs 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:
 
 
 
Six Months Ended June 30,
 
 
 
2012
 
2011
Total capital program costs
 
 
$
182,349

 
$
209,714

Less:
 
 
 
 
 
Exploration expenses
 
 
 
 
 
Seismic
 
 
(320
)
 
(6,137
)
Other, primarily delay rentals
 
 
(501
)
 
(1,702
)
Transfers from tubular inventory and well materials
 
 
(10,775
)
 
(1,576
)
Changes in accrued capitalized costs
 
 
14,617

 
9,692

Add:
 
 
 
 
 
Tubular inventory and well materials purchased in advance of drilling
 
 
2,370

 
—

Capitalized interest
 
 
498

 
990

Other
 
 
(2
)
 
100

Total cash paid for capital expenditures
 
 
$
188,236

 
$
211,081

 
Cash Flows From Financing Activities
 
Cash provided by financing activities during the 2012 period included borrowings under the Revolver while activity during the 2011 period included the effect of issuing the 2019 Senior Notes offset by the repurchase of a substantial portion of the Convertible Notes. Both periods included dividend payments on common stock and the 2011 period includes proceeds received from the exercise of stock options by employees.
 
Financial Condition
 
As of August 1, 2012, after repaying a portion of our outstanding Revolver balance with proceeds from the sale of our Appalachian assets, we had approximately $11 million of cash on hand and $128.3 million of unused borrowing capacity under the Revolver. The borrowing capacity is determined by reducing the borrowing base commitment of $230 million by remaining outstanding borrowings of $100 million and outstanding letters of credit of $1.7 million.
 

37

Credit Facility and Debt
 
The following table summarizes the components our long-term debt as of the dates presented:
 
June 30,
2012
 
December 31,
2011
Revolving credit facility
$
180,000

 
$
99,000

Senior notes due 2016, net of discount (principal amount of $300,000)
294,144

 
293,561

Senior notes due 2019
300,000

 
300,000

Convertible notes due 2012, net of discount (principal amount of $4,915)
4,837

 
4,746

 
778,981

 
697,307

Less: Current portion of long-term debt
(4,837
)
 
(4,746
)
 
$
774,144

 
$
692,561

 
Revolving Credit Facility. 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, or 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%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are being charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2012, the effective interest rate on the borrowings under the Revolver was 2.2500%.
 
The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries, or 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.
 
2016 Senior Notes. The Senior Notes due 2016, or 2016 Senior Notes, bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.
  
2019 Senior Notes. The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of 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.
 
Convertible Notes. The Convertible Notes, which mature in November 2012, are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year.
 
The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.
 
In connection with a tender offer completed in April 2011, we repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, including a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded with the net proceeds of the 2019 Senior Notes offering. Subsequent to the tender offer, a total of $4.9 million aggregate principal amount of Convertible Notes remain outstanding. The remaining unamortized discount will be amortized through November 2012.

38


Covenant Compliance
 
The Revolver requires us to maintain certain financial covenants as follows:
 
•
Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.
•
The current ratio, as of the last day of any quarter, may not be less than 1.0 to 1.0. The current ratio is generally defined as current assets to current liabilities. 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.

As of June 30, 2012 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants. The following table summarizes the actual results of our financial covenant compliance under the Revolver for the period ended June 30, 2012:
Description of Covenant
 
 
Required
Covenant
 
Actual
Results
Total debt to EBITDAX
 
 
< 4.5 to 1
 
3.1 to 1
Current ratio
 
 
> 1.0 to 1
 
2.4 to 1
 
In the event that we would be in default of a covenant under the Revolver, we could request a waiver of the covenant from our bank group. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the Revolver would become payable on demand and would be reclassified as a component of current liabilities on our Condensed Consolidated Balance Sheets. In addition, the Revolver imposes limitations on dividends as well as limits our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.
 
Future Capital Needs and Commitments
 
In 2012, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $325 million. The capital expenditures have been and will continue to be funded primarily by operating cash flows, proceeds from sales of non-strategic assets and borrowing under the Revolver. We recently discontinued our common stock dividend which improves liquidity by increasing available cash flows by approximately $10 million per year. Other potential sources of additional liquidity include an increase in our Revolver borrowing base resulting from an increase in our Eagle Ford Shale proved reserves, third party joint ventures, additional non-strategic asset sales or securities offerings. There can be no assurance, however, that any such actions will be successful. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the availability of capital.
 
Based on expenditures to date and forecasted activity for the remainder of 2012, we expect to allocate capital expenditures as follows: Eagle Ford Shale (92%), Mid-Continent region (7%) and all other areas (1%). This allocation includes approximately 86% for development and exploratory drilling, 7% for leasehold acquisition and 7% for seismic and other projects. We anticipate that we will allocate substantially all of our capital expenditures to oil and NGL projects.

Environmental Matters
 
Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some

39

form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of June 30, 2012, we had recorded asset retirement obligations of $6.4 million attributable to these activities. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates
 
The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011. The following development is discussed with respect to its applicability during the six months ended June 30, 2012 and future periods.
 
Share-Based Compensation
 
In February 2012, we granted performance-based restricted stock units, or PBRSUs, to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.
 
Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period based on the fair value derived from a Monte Carlo model and recognized based on the period of time that has elapsed during each of the individual performance periods. The Monte Carlo model is a binomial valuation model that requires significant judgment with respect to certain assumptions including volatility, dividends and other factors. Due primarily to the sensitivity of certain model assumptions as well as the inherent variability of modeling market-based performance over future periods, our compensation expense with respect to the PBRSUs can be volatile. As an illustration, the expense attributable to the PBRSUs during the three months ended June 30, 2012 was $0.6 million while the expense during the three months ended March 31, 2012 was less than $0.1 million.
 
New Accounting Standards
 
During the quarter ended June 30, 2012, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Condensed Consolidated Financial Statements and Notes.

40


Item 3.
Quantitative and Qualitative Disclosures About Market Risk
 
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.
 
Interest Rate Risk
 
All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Accordingly, changes in interest rates do not affect the amount of interest we pay on our fixed-rate debt instruments. However, changes in interest rates will affect the fair value of our long-term debt instruments. Our interest rate risk is attributable to our borrowings under the Revolver which is subject to variable interest rates. As of June 30, 2012, we had borrowings of $180 million outstanding under the Revolver at an effective interest rate of 2.2500%. Assuming a constant borrowing level of $180 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense of approximately $1.8 million on an annual basis.
 
Commodity Price Risk
 
We produce and sell natural gas, crude oil and NGLs. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars, swaps and swaptions) to seek to mitigate the price risks associated with fluctuations in natural gas, crude oil and NGL prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of natural gas, crude oil and NGLs.
 
As of June 30, 2012, we reported a commodity derivative asset of $39.4 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three 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 not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of June 30, 2012.
 
During the six months ended June 30, 2012, we reported net commodity derivative income of $43.8 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment.  See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

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The following table lists our commodity derivative positions and their fair values as of June 30, 2012:
 
 
 
Average
Volume Per
Day
 
Weighted Average Price
 
Fair Value
 
Instrument
 
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Natural Gas: 
 
 
(in MMBtu)

 
($/MMBtu) 
 
 

 
 

Third quarter 2012
Swaps
 
20,000

 
$
5.31

 
 

 
$
4,594

 
$
—

Fourth quarter 2012
Swaps
 
10,000

 
$
5.10

 
 

 
1,824

 
—

Crude Oil:
 
 
(barrels)

 
($/barrel)

 
 

 
 

 
 
Third quarter 2012
Collars
 
1,000

 
$
90.00

 
$
97.00

 
519

 
—

Fourth quarter 2012
Collars
 
1,000

 
$
90.00

 
$
97.00

 
512

 
—

First quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
518

 
—

Second quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
491

 
—

Third quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
503

 
—

Fourth quarter 2013
Collars
 
1,000

 
$
90.00

 
$
100.00

 
521

 
—

Third quarter 2012
Swaps
 
3,000

 
$
104.40

 
 

 
5,204

 
—

Fourth quarter 2012
Swaps
 
3,000

 
$
104.40

 
 

 
4,817

 
—

First quarter 2013
Swaps
 
2,250

 
$
103.51

 
 

 
3,108

 
—

Second quarter 2013
Swaps
 
2,250

 
$
103.51

 
 

 
3,004

 
—

Third quarter 2013
Swaps
 
1,500

 
$
102.77

 
 

 
1,916

 
—

Fourth quarter 2013
Swaps
 
1,500

 
$
102.77

 
 

 
1,940

 
—

First quarter 2014
Swaps
 
2,000

 
$
100.44

 
 

 
2,166

 
—

Second quarter 2014
Swaps
 
2,000

 
$
100.44

 
 

 
2,232

 
—

Third quarter 2014
Swaps
 
1,500

 
$
100.20

 
 

 
1,687

 
—

Fourth quarter 2014
Swaps
 
1,500

 
$
100.20

 
 

 
1,699

 
—

First quarter 2013
Swaption
 
1,100

 
$
100.00

 
 

 
—

 
290

Second quarter 2013
Swaption
 
1,000

 
$
100.00

 
 

 
—

 
241

Third quarter 2013
Swaption
 
900

 
$
100.00

 
 

 
—

 
180

Fourth quarter 2013
Swaption
 
750

 
$
100.00

 
 

 
—

 
117

First quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
338

Second quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
338

Third quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
339

Fourth quarter 2014
Swaption
 
812

 
$
100.00

 
 

 
—

 
339

Settlements to be received in subsequent period
 
 

 
 

 
 

 
2,086

 
—

 
The following table illustrates the estimated impact on the fair values of our derivative instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This assumes that natural gas prices, crude oil prices and production volumes remain constant at anticipated levels.  The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.
 
 
Change of $1.00 per MMBtu of Natural Gas
or $10.00 per Barrel of Crude Oil
($ in millions)
 
Increase
 
Decrease
Effect on the fair value of natural gas derivatives
$
(2.1
)
 
$
2.0

Effect on the fair value of crude oil derivatives
$
(28.1
)
 
$
18.3

Effect on 2012 operating income, excluding natural gas derivatives
$
9.0

 
$
(9.0
)
Effect on 2012 operating income, excluding crude oil derivatives
$
11.0

 
$
(11.0
)

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Item 4.
Controls and Procedures
 
(a)  Disclosure Controls and Procedures
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2012. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2012, such disclosure controls and procedures were effective.
 
(b)  Changes in Internal Control Over Financial Reporting
 
No changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

43

PART II.     OTHER INFORMATION
Item 6    Exhibits
2.1
Purchase and Sale Agreement dated July 16, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on July 18, 2012).
 
 
2.1.1
Amendment and Supplement to Purchase and Sale Agreement, dated July 31, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on August 2, 2012).
 
 
3.1
Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 7, 2012).
 
 
10.1
Revised Exhibit A to Penn Virginia Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K/A filed on April 3, 2012).
 
 
10.2
Penn Virgina Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on April 12, 2012).
 
 
12.1
Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
 
 
31.1
Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
31.2
Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101.INS
XBRL Instance Document
 
 
101.SCH
XBRL Taxonomy Extension Schema Document
 
 
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
 
 
101.LAB
XBRL Taxonomy Extension Label Linkbase Document
 
 
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document

44

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
PENN VIRGINIA CORPORATION
 
 
 
Date:   August 2, 2012
By:
/s/ Steven A. Hartman
 
 
Steven A. Hartman
 
 
Senior Vice President and Chief Financial Officer
 
 
 
Date:   August 2, 2012
By:
/s/ Joan C. Sonnen
 
 
Joan C. Sonnen
 
 
Vice President and Controller

45