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BAYTEX ENERGY USA, INC. - Quarter Report: 2013 March (Form 10-Q)



 
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 March 31, 2013 
or
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from              to              
 Commission file number: 1-13283
 _________________________________________________________ 
PENN VIRGINIA CORPORATION
(Exact name of registrant as specified in its charter)
__________________________________________________________
Virginia
 
23-1184320
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification Number)
FOUR RADNOR CORPORATE CENTER, SUITE 200
100 MATSONFORD ROAD
RADNOR, PA 19087
(Address of principal executive offices) (Zip Code)
(610) 687-8900
(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)
__________________________________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 ("Exchange Act") during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý  No  ¨
 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer
¨
Accelerated filer
ý
Non-accelerated filer
¨
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  ¨    No  ý
 As of May 3, 2013, 65,222,907 shares of common stock of the registrant were outstanding.
 





PENN VIRGINIA CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013
 Table of Contents
Part I - Financial Information
Item
 
Page
1.
Financial Statements:
 
 
Condensed Consolidated Statements of Operations for the Periods Ended March 31, 2013 and 2012
 
Condensed Consolidated Statements of Comprehensive Income for the Periods Ended March 31, 2013 and 2012
 
Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012
 
Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2013 and 2012
 
Notes to Condensed Consolidated Financial Statements:
 
 
1. Organization
 
2. Basis of Presentation
 
3. Acquisitions and Divestitures
 
4. Accounts Receivable and Major Customers
 
5. Derivative Instruments
 
6. Property and Equipment
 
7. Long-Term Debt
 
8. Additional Balance Sheet Detail
 
9. Fair Value Measurements
 
10. Commitments and Contingencies
 
11. Shareholders' Equity
 
12. Share-Based Compensation
 
13. Restructuring and Exit Activities
 
14. Interest Expense
 
15. Earnings per Share
Forward-Looking Statements
2.
Management's Discussion and Analysis of Financial Condition and Results of Operations:
 
 
Overview of Business
 
Key Developments
 
Results of Operations
 
Liquidity and Capital Resources
 
Environmental Matters
 
Critical Accounting Estimates
 
New Accounting Standards
3.
Quantitative and Qualitative Disclosures About Market Risk
4.
Controls and Procedures
Part II - Other Information
1A.
Risk Factors
6.
Exhibits
Signatures




Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited
(in thousands, except per share data) 
 
Three Months Ended March 31,
 
2013
 
2012
Revenues
 

 
 

Crude oil
$
63,058

 
$
58,723

Natural gas liquids (NGLs)
7,127

 
9,071

Natural gas
12,039

 
14,886

(Loss) gain on sales of property and equipment, net
(549
)
 
756

Other
1,523

 
975

Total revenues
83,198

 
84,411

Operating expenses
 

 
 

Lease operating
7,805

 
9,143

Gathering, processing and transportation
3,579

 
4,154

Production and ad valorem taxes
5,959

 
3,580

General and administrative
10,943

 
12,141

Exploration
6,295

 
7,998

Depreciation, depletion and amortization
51,576

 
50,817

Total operating expenses
86,157

 
87,833

Operating loss
(2,959
)
 
(3,422
)
Other income (expense)
 

 
 

Interest expense
(14,479
)
 
(14,774
)
Derivatives
(7,761
)
 
(305
)
Other
27

 
1

Loss from operations before income taxes
(25,172
)
 
(18,500
)
Income tax benefit
8,789

 
6,601

Net loss
(16,383
)
 
(11,899
)
Preferred stock dividends
(1,725
)
 

Loss attributable to common shareholders
$
(18,108
)
 
$
(11,899
)
Loss per share:
 

 
 

Basic
$
(0.33
)
 
$
(0.26
)
Diluted
$
(0.33
)
 
$
(0.26
)
 
 
 
 
Weighted average shares outstanding - basic
55,341

 
45,945

Weighted average shares outstanding - diluted
55,341

 
45,945


See accompanying notes to condensed consolidated financial statements.

3



PENN VIRGINIA CORPORATION AND SUBSIDIARIES 
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - unaudited
(in thousands) 
 
Three Months Ended March 31,
 
2013
 
2012
Net loss
$
(16,383
)
 
$
(11,899
)
Other comprehensive income:
 

 
 

Change in pension and postretirement obligations, net of tax of $10 in 2013 and $13 in 2012
19

 
23

 
19

 
23

Comprehensive loss
$
(16,364
)
 
$
(11,876
)
 
See accompanying notes to condensed consolidated financial statements.

4



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands, except share data)
 
As of
 
March 31,
 
December 31,
 
2013
 
2012
Assets
 

 
 

Current assets
 

 
 

Cash and cash equivalents
$
14,422

 
$
17,650

Accounts receivable, net of allowance for doubtful accounts
64,378

 
62,978

Derivative assets
5,900

 
11,292

Other current assets
3,961

 
4,595

Total current assets
88,661

 
96,515

Property and equipment, net (successful efforts method)
1,760,240

 
1,723,359

Derivative assets
3,608

 
5,181

Other assets
17,292

 
17,934

Total assets
$
1,869,801

 
$
1,842,989

 
 
 
 
Liabilities and Shareholders’ Equity
 

 
 

Current liabilities
 

 
 

Accounts payable and accrued liabilities
$
121,967

 
$
111,655

Derivative liabilities
4,539

 

Deferred income taxes
573

 
370

Total current liabilities
127,079

 
112,025

Other liabilities
28,518

 
28,901

Derivative liabilities
1,235

 
1,421

Deferred income taxes
202,196

 
210,767

Long-term debt
633,080

 
594,759

 
 
 
 
Commitments and contingencies (Note 10)


 


 
 
 
 
Shareholders’ equity:
 

 
 

Preferred stock of $100 par value – 100,000 shares authorized; 11,500 shares issued as of March 31, 2013 and December 31, 2012 with a redemption value of $10,000 per share
1,150

 
1,150

Common stock of $0.01 par value – 128,000,000 shares authorized; 55,222,907 and 55,117,346 shares issued as of March 31, 2013 and December 31, 2012, respectively
365

 
364

Paid-in capital
849,710

 
849,046

Retained earnings
27,682

 
45,790

Deferred compensation obligation
3,176

 
3,111

Accumulated other comprehensive loss
(963
)
 
(982
)
Treasury stock – 234,253 and 218,320 shares of common stock, at cost, as of March 31, 2013 and December 31, 2012, respectively
(3,427
)
 
(3,363
)
Total shareholders’ equity
877,693

 
895,116

Total liabilities and shareholders’ equity
$
1,869,801

 
$
1,842,989


See accompanying notes to condensed consolidated financial statements.

5



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
 
Three Months Ended March 31,
 
2013
 
2012
Cash flows from operating activities
 

 
 

Net loss
$
(16,383
)
 
$
(11,899
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 

 
 

Depreciation, depletion and amortization
51,576

 
50,817

Derivative contracts:
 

 
 

Net losses
7,761

 
305

Cash settlements
3,557

 
7,981

Deferred income tax benefit
(8,789
)
 
(6,601
)
Loss (gain) on sales of assets, net
549

 
(756
)
Non-cash exploration expense
5,262

 
8,171

Non-cash interest expense
946

 
1,015

Share-based compensation (equity-classified)
1,085

 
1,615

Other, net
288

 
56

Changes in operating assets and liabilities
(237
)
 
19,997

Net cash provided by operating activities
45,615

 
70,701

Cash flows from investing activities
 

 
 

Capital expenditures - property and equipment
(85,973
)
 
(94,469
)
Proceeds from sales of assets, net
878

 
778

Net cash used in investing activities
(85,095
)
 
(93,691
)
Cash flows from financing activities
 

 
 

Proceeds from revolving credit facility borrowings
38,000

 
23,000

Repayment of revolving credit facility borrowings

 
(3,000
)
Dividends paid on preferred stock
(1,687
)
 

Dividends paid on common stock

 
(2,586
)
Other, net
(61
)
 

Net cash provided by financing activities
36,252

 
17,414

Net decrease in cash and cash equivalents
(3,228
)
 
(5,576
)
Cash and cash equivalents - beginning of period
17,650

 
7,512

Cash and cash equivalents - end of period
$
14,422

 
$
1,936

Supplemental disclosures:
 

 
 

Cash paid for:
 

 
 

Interest (net of amounts capitalized)
$
340

 
$
557

Income taxes (net of refunds received)
$

 
$
(301
)
 
See accompanying notes to condensed consolidated financial statements.

6



PENN VIRGINIA CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - unaudited
For the Quarterly Period Ended March 31, 2013
(in thousands, except per share amounts)

1. 
Organization
 
Penn Virginia Corporation (“Penn Virginia,”, “we,” “us” or “our”) is an independent oil and gas company engaged primarily in the exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas in various domestic onshore regions of the United States with a primary focus in Texas, and to a lesser extent, the Mid-Continent, Mississippi and the Marcellus Shale in Appalachia.

2.
Basis of Presentation
 
Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2012. Operating results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. Certain amounts for the 2012 period have been reclassified to conform to the current year presentation.
 
During the quarter ended March 31, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 11. The adoption of ASU 2013-02 did not 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 our Condensed Consolidated Financial Statements were issued, and concluded that, except for the transactions discussed below, no additional subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.

Subsequent Events

The transactions described below occurred subsequent to the closing of our quarterly reporting period that ended on March 31, 2013 and will be recorded during the second quarter of 2013. Because these transactions are significant to us, we are providing disclosures required by U.S. GAAP.

On April 24, 2013 (the “Date of Acquisition”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from Magnum Hunter Resources Corporation (“MHR”) for approximately $400 million (the “Acquisition”) consisting of approximately $360 million in cash and 10 million shares of our common stock (the “Shares”) with an effective date of January 1, 2013. See Note 11 for a description of the rights and obligations related to the Shares issued to MHR. The Acquisition includes approximately 40,600 gross (19,000 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired assets also include working interests in 46 gross (22.1 net) producing wells. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 million barrels of oil equivalent, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.

We will account for the Acquisition by applying the acquisition method of accounting in the second quarter of 2012. The initial accounting for the Acquisition as presented below is based upon preliminary information and was not complete as of the date our Condensed Consolidated Financial Statements were issued. Accordingly, adjustments to the initial accounting for the acquired net assets will likely occur as we obtain additional information and complete a more detailed analysis regarding the facts and circumstances that existed as of the Date of Acquisition.


7



The following table represents the preliminary fair values of the net assets acquired at the Date of Acquisition:
Assets
 
 
Oil and gas properties - proved
 
$
247,709

Oil and gas properties - unproved
 
172,367

Other assets
 
15,100

 
 
435,176

Liabilities
 
 
Accounts payable and accrued expenses
 
(31,000
)
Other liabilities
 
(1,500
)
 
 
(32,500
)
Net asset acquired
 
$
402,676


The fair values of the net assets acquired were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted-average cost of capital. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in U.S. GAAP.

The results of operations attributable to the Acquisition from the Date of Acquisition will be included in our Condensed Consolidated Financial Statements for the period ended June 30, 2013. The following table presents unaudited summary pro forma financial information for the year ended December 31, 2012 assuming the Acquisition occurred as of January 1, 2012. The pro forma financial information does not purport to represent what our results of operations would have been if the Acquisition had occurred as of this date or the results of operations for any future periods.
Total revenues
 
$
389,260

Net loss
 
$
(160,555
)
Loss per share - basic and diluted
 
$
(2.77
)

On April 11, 2013, we initiated a tender offer (the “Tender Offer”) for any and all of the total $300 million principal amount of our 10.375% Senior Notes due 2016 (the “2016 Senior Notes”). As of April 24, 2013, holders of approximately 58% of the $300 million total principal amount of the 2016 Senior Notes outstanding had tendered their 2016 Senior Notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered by April 24, 2013, was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. On April 25, 2013, we paid a total of approximately $191 million, including accrued interest of $6.5 million, for the 2016 Senior Notes tendered. On May 6, 2013, we made an irrevocable election to redeem (the "Redemption") on May 10, 2013 the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We will pay a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes in connection with the Redemption. We will recognize a loss on the extinguishment of debt of approximately $29 million in connection with the Tender Offer and the Redemption, which will be recorded in the second quarter of 2013.

On April 24, 2013, we completed a private placement of $775 million of 8.5% Senior Notes due 2020 Senior Notes (the “2020 Senior Notes”). The 2020 Senior Notes were priced at par and interest will be payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by all of our material subsidiaries (the “Guarantor Subsidiaries”). Approximately $380 million of the net proceeds from the private placement, together with the Shares, were used to finance the Acquisition, including purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the revolving credit facility (the “Revolver”) and to fund a portion of the Tender Offer and the Redemption.

3.
Acquisitions and Divestitures
 
Divestitures
 
In 2012, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia. The assignment of certain properties in West Virginia subject to this sale was not completed until January 2013 at which time we received $0.5 million in proceeds, net of transaction costs.
  

8



4.       Accounts Receivable and Major Customers
 
The following table summarizes our accounts receivable by type as of the dates presented:
 
As of
 
March 31,
 
December 31,
 
2013
 
2012
Customers
$
49,978

 
$
43,967

Joint interest partners
13,197

 
16,154

Other
2,851

 
4,523

 
66,026

 
64,644

Less: Allowance for doubtful accounts
(1,648
)
 
(1,666
)
 
$
64,378

 
$
62,978

 
For the three months ended March 31, 2013, four customers accounted for $46.2 million, or approximately 56%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2013 were $16.1 million, $10.9 million, $10.6 million and $8.6 million or 20%, 13%, 13% and 10% of the consolidated total, respectively. As of March 31, 2013, $23.8 million, or approximately 37% of our consolidated accounts receivable, including joint interest billings, related to these customers. For the three months ended March 31, 2012, two customers accounted for $32.9 million, or approximately 40% of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2012 were $16.8 million and $16.1 million, or approximately 20% and 19% of the consolidated total, respectively. As of December 31, 2012, $10.1 million, or approximately 16% 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 any of these customers.

5.
Derivative Instruments
 
We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility as well as the volatility in interest rates attributable to our debt instruments. Our derivative instruments are not formally designated as hedges. The disclosures included herein incorporate the requirements of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities as amended by Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.
 
Commodity Derivatives
 
We utilize collars, swaps and swaptions, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.
 
The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. A swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for the term of the swaption is higher than or equal to the swaption strike price on the exercise date, the counterparty will exercise its option to enter into a fixed price swap at the swaption strike price for the term of the swaption, at which point the contract functions as a fixed price swap. If the forward commodity price for the term of the swaption is lower than the swaption strike price on the exercise date, the option expires and no fixed price swap is in effect.

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.


9



The following table sets forth our commodity derivative positions as of March 31, 2013:
 
 
 
Average
 
 
 
 
 
 
 
 
 
Volume Per
 
Weighted Average Price
 
Fair Value
 
Instrument
 
Day
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Crude Oil:
 
 
(barrels)
 
($/barrel)
 
 
 
 
Second quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 
$

 
$
164

Third quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 

 
235

Fourth quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 

 
81

Second quarter 2013
Swaps
 
3,750

 
$
101.26

 
 
 
1,460

 
173

Third quarter 2013
Swaps
 
4,000

 
$
98.43

 
 
 
1,038

 
550

Fourth quarter 2013
Swaps
 
4,000

 
$
98.43

 
 
 
1,355

 
357

First quarter 2014
Swaps
 
4,000

 
$
95.27

 
 
 
1,093

 
720

Second quarter 2014
Swaps
 
4,000

 
$
95.27

 
 
 
1,312

 
519

Third quarter 2014
Swaps
 
3,500

 
$
94.43

 
 
 
1,096

 
347

Fourth quarter 2014
Swaps
 
3,500

 
$
94.43

 
 
 
1,199

 
210

First quarter 2014
Swaptions
 
1,812

 
$
100.00

 
 
 

 
281

Second quarter 2014
Swaptions
 
1,812

 
$
100.00

 
 
 

 
280

Third quarter 2014
Swaptions
 
1,812

 
$
100.00

 
 
 

 
280

Fourth quarter 2014
Swaptions
 
1,812

 
$
100.00

 
 
 

 
280

 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas:
 
 
(in MMBtu)

 
($/MMBtu)
 
 

 
 
Second quarter 2013
Collars
 
10,000

 
$
3.50

 
$
4.30

 

 
34

Third quarter 2013
Collars
 
10,000

 
$
3.50

 
$
4.30

 

 
125

Fourth quarter 2013
Collars
 
15,000

 
$
3.67

 
$
4.37

 
15

 
222

First quarter 2014
Collars
 
5,000

 
$
4.00

 
$
4.50

 

 
58

Second quarter 2013
Swaps
 
15,000

 
$
3.92

 
 

 
13

 
151

Third quarter 2013
Swaps
 
15,000

 
$
3.92

 
 

 

 
271

Fourth quarter 2013
Swaps
 
10,000

 
$
4.04

 
 

 

 
160

First quarter 2014
Swaps
 
5,000

 
$
4.05

 
 
 

 
145

Second quarter 2014
Swaps
 
10,000

 
$
4.03

 
 
 

 
53

Third quarter 2014
Swaps
 
10,000

 
$
4.03

 
 
 

 
105

Settlements to be received in subsequent period
 
 
 

 
 

 
 

 
954

 


Interest Rate Swaps
 
In February 2012, we entered into an interest rate swap agreement to establish variable interest rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds. As of March 31, 2013, we had no interest rate derivative instruments outstanding.

10



Financial Statement Impact of Derivatives
 
The impact of our derivatives activities on income is included in the Derivatives caption on our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:
 
Three Months Ended March 31,
 
2013
 
2012
Impact by contract type:
 

 
 

Commodity contracts
$
(7,761
)
 
$
294

Interest rate contracts

 
(599
)
 
$
(7,761
)
 
$
(305
)
Realized and unrealized impact:
 

 
 

Cash received for:
 

 
 

Commodity contract settlements
$
3,557

 
$
7,981

Interest rate contract settlements

 

 
3,557

 
7,981

Unrealized losses attributable to:
 

 
 

Commodity contracts
(11,318
)
 
(7,687
)
Interest rate contracts

 
(599
)
 
(11,318
)
 
(8,286
)
 
$
(7,761
)
 
$
(305
)
 
The effects of derivative gains and losses and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net loss to net cash provided by operating activities. These items are recorded in the Derivative contracts: Net losses and Derivative contracts: Cash settlements captions on our Condensed Consolidated Statements of Cash Flows.
 
The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments, on our Condensed Consolidated Balance Sheets as of the dates presented:
 
 
 
 
Fair Values as of
 
 
 
 
March 31, 2013
 
December 31, 2012
 
 
 
 
Derivative
 
Derivative
 
Derivative
 
Derivative
Type
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
Commodity contracts
 
Derivative assets/liabilities - current
 
$
5,900

 
$
4,539

 
$
11,292

 
$

Interest rate contracts
 
Derivative assets/liabilities - current
 

 

 

 

 
 
 
 
5,900

 
4,539

 
11,292

 

 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
Derivative assets/liabilities - noncurrent
 
3,608

 
1,235

 
5,181

 
1,421

Interest rate contracts
 
Derivative assets/liabilities - noncurrent
 

 

 

 

 
 
 
 
3,608

 
1,235

 
5,181

 
1,421

 
 
 
 
$
9,508

 
$
5,774

 
$
16,473

 
$
1,421


As of March 31, 2013, we reported a commodity derivative asset of $9.5 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.


11



6.
Property and Equipment
 
The following table summarizes our property and equipment as of the dates presented: 
 
As of
 
March 31,
 
December 31,
 
2013
 
2012
Oil and gas properties:
 

 
 

Proved
$
2,362,690

 
$
2,277,811

Unproved
54,641

 
60,746

Total oil and gas properties
2,417,331

 
2,338,557

Other property and equipment
95,221

 
93,648

Total property and equipment
2,512,552

 
2,432,205

Accumulated depreciation, depletion and amortization
(752,312
)
 
(708,846
)
 
$
1,760,240

 
$
1,723,359

 

7.
Long-Term Debt
 
The following table summarizes our long-term debt as of the dates presented:

 
As of
 
March 31,
 
December 31,
 
2013
 
2012
Revolving credit facility
$
38,000

 
$

Senior notes due 2016, net of discount (principal amount of $300,000)
295,080

 
294,759

Senior notes due 2019
300,000

 
300,000

 
$
633,080

 
$
594,759


Revolving Credit Facility
 
The Revolver provides for a $300 million revolving commitment and an accordion feature that allows us to increase the commitment by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver was established at $300 million. Subsequent to the private placement of the 2020 Senior Notes in April 2013, as discussed in Note 2, our borrowing base under the Revolver was reduced by $23.8 million to $276.2 million. The borrowing base will be re-determined by the end of May 2013, and semi-annually thereafter, based on a review of our total proved oil, NGL and natural gas reserves. Proved oil, NGL and natural gas reserves from the Acquisition will be considered in the May 2013 re-determination. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $2.8 million outstanding as of March 31, 2013. As of March 31, 2013, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $259.2 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, 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% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of March 31, 2013, the actual interest rate on the outstanding borrowings under the Revolver was 1.75%.


12



The Revolver is guaranteed by Penn Virginia and the Guarantor Subsidiaries. The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.

The guarantees provided by Penn Virginia, which is the parent company of all of our subsidiaries, 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.

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 through December 31, 2013, 4.25 to 1.0 through June 30, 2014 and then 4.0 to 1.0 through maturity.

2016 Senior Notes
 
The 2016 Senior Notes were originally sold at 97% of par in June 2009, 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. 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. As discussed in Note 2, none of the $300 million principal amount of the 2016 Senior Notes will remain outstanding subsequent to May 10, 2013 as a result of the Tender Offer and the Redemption.

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.
 


13



8.
Additional Balance Sheet Detail
 
The following table summarizes components of selected balance sheet accounts as of the dates presented:
 
As of
 
March 31,
 
December 31,
 
2013
 
2012
Other current assets:
 

 
 

Tubular inventory and well materials
$
2,879

 
$
4,033

Prepaid expenses
1,082

 
562

 
$
3,961

 
$
4,595

Other assets:
 

 
 

Debt issuance costs
$
12,613

 
$
13,186

Assets of supplemental employee retirement plan (“SERP”)
3,401

 
3,237

Other
1,278

 
1,511

 
$
17,292

 
$
17,934

Accounts payable and accrued liabilities:
 

 
 

Trade accounts payable
$
31,335

 
$
37,835

Drilling costs
43,858

 
37,703

Royalties
13,559

 
14,390

Production and franchise taxes
4,820

 
2,874

Compensation - related
2,713

 
6,853

Interest
19,072

 
5,828

Preferred stock dividends
1,725

 
1,687

Other
4,885

 
4,485

 
$
121,967

 
$
111,655

Other liabilities:
 

 
 

Firm transportation obligation
$
13,870

 
$
14,333

Asset retirement obligations (“AROs”)
4,551

 
4,513

Defined benefit pension obligations
1,786

 
1,821

Postretirement health care benefit obligations
2,699

 
2,634

Deferred compensation - SERP obligation and other
3,469

 
3,310

Other
2,143

 
2,290

 
$
28,518

 
$
28,901



14




9.
Fair Value Measurements
 
We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of March 31, 2013, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.
 
The following table summarizes the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for these debt obligations, as of the dates presented:
 
As of
 
March 31, 2013
 
December 31, 2012
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
Senior Notes due 2016
$
318,000

 
$
295,080

 
$
316,500

 
$
294,759

Senior Notes due 2019
298,875

 
300,000

 
286,500

 
300,000

 
$
616,875

 
$
595,080

 
$
603,000

 
$
594,759

 
Recurring Fair Value Measurements
 
Certain financial assets and liabilities are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:
 
 
As of March 31, 2013
 
 
Fair Value
 
Fair Value Measurement Classification
Description
 
Measurement
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 

 
 

 
 

 
 

Commodity derivative assets - current
 
$
5,900

 
$

 
$
5,900

 
$

Commodity derivative assets - noncurrent
 
3,608

 

 
3,608

 

Assets of SERP
 
3,401

 
3,401

 

 

 
 
 
 
 
 
 
 
 
Liabilities:
 
 

 
 

 
 

 
 

Commodity derivative liabilities - current
 
(4,539
)
 

 
(4,539
)
 

Commodity derivative liabilities - noncurrent
 
(1,235
)
 

 
(1,235
)
 

Deferred compensation - SERP obligation
 
(3,464
)
 
(3,464
)
 

 

 
 
As of December 31, 2012
 
 
Fair Value
 
Fair Value Measurement Classification
Description
 
Measurement
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 

 
 

 
 

 
 

Commodity derivative assets - current
 
$
11,292

 
$

 
$
11,292

 
$

Commodity derivative assets - noncurrent
 
5,181

 

 
5,181

 

Assets of SERP
 
3,237

 
3,237

 

 

Liabilities:
 
 

 
 

 
 

 
 

Commodity derivative liabilities - noncurrent
 
(1,421
)
 

 
(1,421
)
 

Deferred compensation - SERP obligation
 
(3,305
)
 
(3,305
)
 

 


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 months ended March 31, 2013 and 2012.

15



We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.
Assets of SERP: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.
Deferred compensation - SERP obligations 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 utilized in the preparation of our Condensed Consolidated Financial Statements include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of 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

Drilling and Completion Commitments
 
We have agreements to purchase oil and gas well drilling and well completion services from third parties with original terms of up to 3 years. As of March 31, 2013, there were no well drilling or well completion agreements with terms that extended beyond September 30, 2013. The well drilling agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term and declines as time passes. As of March 31, 2013, the penalty amount would have been $3.8 million if we had terminated our agreements on that date.
 
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 March 31, 2013. In addition to the reserve for litigation, we maintain a suspense account which includes approximately $1.8 million representing the excess of revenues received over costs incurred attributable to these properties. As of March 31, 2013, we also have AROs of approximately $4.6 million attributable to the plugging of abandoned wells.
 

16



11.
Shareholders’ Equity
 
The following tables summarizes the components of our shareholders' equity and the changes therein as of and for the three months ended March 31, 2013 and 2012:
 
As of
 
 
 
 
 
 
 
As of
 
December 31,
 
 
 
Dividends
 
All Other
 
March 31,
 
2012
 
Net Loss
 
Declared 1
 
Changes
 
2013
Preferred stock
$
1,150

 
$

 
$

 
$

 
$
1,150

Common stock
364

 

 

 
1

 
365

Paid-in capital
849,046

 

 

 
664

 
849,710

Retained earnings
45,790

 
(16,383
)
 
(1,725
)
 

 
27,682

Deferred compensation obligation
3,111

 

 

 
65

 
3,176

Accumulated other comprehensive loss 2
(982
)
 

 

 
19

 
(963
)
Treasury stock
(3,363
)
 

 

 
(64
)
 
(3,427
)
 
$
895,116

 
$
(16,383
)
 
$
(1,725
)
 
$
685

 
$
877,693

 
 
 
 
 
 
 
 
 
 
 
As of
 
 
 
 
 
 
 
As of
 
December 31,
 
 
 
Dividends
 
All Other
 
March 31,
 
2011
 
Net Loss
 
Declared 3
 
Changes
 
2012
Common stock
$
270

 
$

 
$

 
$
1

 
$
271

Paid-in capital
690,131

 

 

 
1,614

 
691,745

Retained earnings
157,242

 
(11,899
)
 
(2,586
)
 

 
142,757

Deferred compensation obligation
3,620

 

 

 
40

 
3,660

Accumulated other comprehensive loss 2
(1,084
)
 

 

 
23

 
(1,061
)
Treasury stock
(3,870
)
 

 

 
(41
)
 
(3,911
)
 
$
846,309

 
$
(11,899
)
 
$
(2,586
)
 
$
1,637

 
$
833,461

_______________________
1 Includes dividends of $150.00 per share of 6% Convertible Perpetual Preferred Stock (the “6% Preferred Stock”).
2 The Accumulated other comprehensive loss ("AOCL") is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCL for the three months ended March 31, 2013 and 2012 represent reclassifications from AOCL to net periodic benefit expense, a component of General and administrative expenses, of $29 and $36 and are presented above net of taxes of $10 and $13.
3 Includes dividends of $0.05625 per share of common stock.

As discussed in Note 2, we issued the Shares to MHR in April 2013 as part of the total consideration paid in connection with the Acquisition. The Shares were not registered in connection with their issuance. In connection with the Shares issued to MHR, we entered into a Registration Rights, Lock-Up and Buy-Back Agreement (the “Registration Rights Agreement”) and a Standstill Agreement (the “Standstill Agreement”). The Registration Rights Agreement requires us to file a resale registration statement (the “Registration Statement”) with respect to the Shares promptly following the closing date of the Acquisition and use our commercially reasonable efforts to cause the Registration Statement to become effective as promptly as practicable. In limited circumstances, MHR will have piggyback registration rights.

Under the Registration Rights Agreement, we are obligated, at MHR's election, to use up to 50% of the net proceeds of any public or private offering of our common stock prior to the effectiveness of the Registration Statement, and 25% of such net proceeds after the effectiveness of the Registration Statement, to repurchase Shares. This buyback obligation will terminate on the first anniversary of the effective date of the Registration Statement or, if earlier, the date upon which the Shares owned by MHR constitute less than 5% of our outstanding common stock.

Under the Standstill Agreement, MHR may not take certain actions intended to cause a change in control of us and has granted an irrevocable proxy to vote the Shares. The Standstill Agreement will terminate on April 24, 2016 or, if earlier, the date upon which the Shares owned by MHR constitute less than 10% of our outstanding common stock.


17



12.
Share-Based Compensation

Our stock compensation plans (collectively, the “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. We recognize compensation expense related to our Stock Compensation Plans in the General and administrative caption on our Condensed Consolidated Statement of Operations.

With the exception of performance-based restricted stock units (“PBRSUs”), all 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 compensation cost attributable to these awards is measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.

The following table summarizes our share-based compensation expense recognized for the periods presented:
 
Three Months Ended March 31,
 
2013
 
2012
Equity-classified awards:
 
 
 
Stock option awards
$
792

 
$
1,208

Common, deferred and restricted stock and stock unit awards
293

 
407

 
1,085

 
1,615

Liability-classified awards
14

 
72

 
$
1,099

 
$
1,687


13.
Restructuring and Exit Activities
 
During 2012, we completed an organizational restructuring in conjunction with the sale of our legacy natural gas assets in West Virginia, Kentucky and Virginia. We terminated approximately 30 employees and closed our regional office in Canonsburg, Pennsylvania. In addition, we have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale, we no longer have production to satisfy this commitment. While we intend to sell our unused firm transportation in the future to the extent possible, we recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The activity summarized below includes contractual payments on the obligation as well as the recognition of accretion expense.

The following table summarizes our restructuring and exit activity-related obligations and the changes therein as of and for the periods presented:
 
Three Months Ended March 31,
 
2013
 
2012
Balance at beginning of period
$
17,263

 
$
576

Employee, office and other costs accrued, net

 
(3
)
Accretion of firm transportation obligation
207

 

Cash payments, net
(498
)
 
(98
)
Balance at end of period
$
16,972

 
$
475


Restructuring charges are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations. The initial charge for the firm transportation commitment was presented as a separate caption on our Consolidated Statement of Operations for the year ended December 31, 2012. The accretion of this obligation, net of any recoveries from the periodic sale of our contractual capacity, is charged as an offset to Other revenue. The current portion of these restructuring and exit cost obligations is included in the Accounts payable and accrued expenses caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of March 31, 2013, $3.0 million of the total obligations are classified as current while the remaining $14.0 million are classified as noncurrent.

18




14.
Interest Expense
 
The following table summarizes the components of interest expense for the periods presented:
 
Three Months Ended March 31,
 
2013
 
2012
Interest on borrowings and related fees
$
13,583

 
$
14,017

Accretion of original issue discount
321

 
333

Amortization of debt issuance costs
626

 
682

Capitalized interest
(51
)
 
(258
)
 
$
14,479

 
$
14,774


15.
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 March 31,
 
2013
 
2012
Net loss
(16,383
)
 
(11,899
)
Less: Preferred stock dividends
(1,725
)
 

Loss attributable to common shareholders - Basic and Diluted
$
(18,108
)
 
$
(11,899
)
 
 
 
 
Weighted-average shares - Basic
55,341

 
45,945

Effect of dilutive securities 1

 

Weighted-average shares - Diluted
55,341

 
45,945

_______________________
1 For the three months ended March 31, 2013 and 2012, respectively, approximately 19.2 million and less than 0.1 million potentially dilutive securities, including the 6% Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.


19



Forward-Looking Statements
 
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: 
the volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas;
our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
any impairments, write-downs or write-offs of our reserves or assets;
the projected demand for and supply of oil, NGLs and natural gas;
reductions in the borrowing base under our revolving credit facility;
our ability to contract for drilling rigs, supplies and services at reasonable costs;
our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices;
the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves;
drilling and operating risks;
our ability to compete effectively against other 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 Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2012.
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.



20



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,” “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, natural gas liquids, or NGLs, and natural gas in various domestic onshore regions. We have a geographically diverse asset base with active operations in Texas, the Mid-Continent and Mississippi regions. Our operations are concentrated primarily in the Eagle Ford Shale, and to a lesser extent, the Granite Wash, Haynesville Shale, Cotton Valley and Selma Chalk plays. As of December 31, 2012, we had proved oil and natural gas reserves of approximately 113.5 million barrels of oil equivalent, or MMBOE. Our current operations consist primarily of the drilling of unconventional horizontal development wells in shale formations.
 
We are currently focused on development and expansion in the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in the 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 March 31,
 
2013
 
2012
Total production (MBOE)
1,427.1

 
1,812.4

Daily production (BOEPD)
15,857

 
19,916

 
 
 
 
Product revenues, as reported
$
82,224

 
$
82,680

Product revenues, as adjusted for derivatives
$
85,781

 
$
90,661

 
 
 
 
Cash provided by operating activities
$
45,615

 
$
70,701

Cash paid for capital expenditures
$
85,973

 
$
94,469

 
 
 
 
Cash and cash equivalents at end of period
$
14,422

 
$
1,936

Debt outstanding, net of discounts, at end of period
$
633,080

 
$
717,639

Liquidation preference of convertible preferred stock outstanding at end of period
$
115,000

 
$

Credit available under revolving credit facility at end of period 1
$
259,222

 
$
179,600

 
 
 
 
Net development wells drilled
8.5

 
7.5

Net exploratory wells drilled

 
1.9

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


21



Key Developments

The following general business developments and corporate actions will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) completing our acquisition of Magnum Hunter Resource Corporation's, or MHR, Eagle Ford Shale assets, or the Acquisition, (ii) drilling results in the Eagle Ford Shale and other plays, (iii) initiating a tender offer, or the Tender Offer, for our 10.375% Senior Notes due 2016, or 2016 Senior Notes, as well as a redemption, or the Redemption, for all 2016 Senior Notes not acquired through the Tender Offer (v) completing a private placement of $775 million of 8.5% Senior Notes due 2020, or 2020 Senior Notes, to finance the Acquisition and the Tender Offer and (vi) hedging a portion of our oil and natural gas production through calendar year 2014 to the levels permitted by our revolving credit facility, or Revolver, and our internal policies.

Acquisition of Magnum Hunter's Eagle Ford Shale Assets

On April 24, 2013, we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from MHR for approximately $400 million consisting of approximately $360 million in cash and 10 million shares of our common stock, or the Shares. The effective date of the Acquisition was January 1, 2013. The Acquisition includes approximately 40,600 gross (19,000 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired assets also include working interests in 46 gross (22.1 net) producing wells. Estimated net oil and gas production for the acquired assets during 2013 is approximately 2,700 barrels of oil per day equivalent, or BOEPD. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 MMBOE, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.

As a result of the Acquisition, we have approximately 80,200 gross (54,200 net) contiguous acres, the majority of which are in the volatile oil window of the Eagle Ford Shale, approximately 66,900 gross (47,700 net) acres of which are operated by us. Including those acquired in the Acquisition, we currently have a total of 120 gross (84.2 net) Eagle Ford Shale producing wells, with 15 gross (8.8 net) wells either completing or waiting on completion and seven gross (4.1 net) wells being drilled through the first week of May 2013. On a pro forma basis, the Acquisition would have brought our total production to approximately 19,500 BOEPD and our Eagle Ford Shale production in 2013 to approximately 10,900 BOEPD. Our 2013 total production is expected to increase by approximately 3,700 to 4,400 BOEPD for the remainder of 2013, with net capital expenditures expected to increase by approximately $72 to $82 million. We estimate that additional net operating cash flows, prior to interest expense, will be approximately $60 to $70 million during the same period. 

Drilling Results and Future Development Plans
 
During the three months ended March 31, 2013, we drilled nine gross (8.2 net) operated wells in the Eagle Ford Shale all of which were successful. We also drilled one non-operated gross (0.3 net) well in the Granite Wash which is currently under evaluation. Our Eagle Ford Shale production was approximately 7,523 net BOEPD during the three months ended March 31, 2013 with oil comprising approximately 78 percent, NGLs approximately 12 percent and natural gas approximately 10 percent. We have allocated approximately 94 percent of our anticipated capital expenditures during 2013 to activities in the Eagle Ford Shale.

Tender Offer for the 2016 Senior Notes

On April 11, 2013, we initiated the Tender Offer for any and all of the total $300 million principal amount of our 2016 Senior Notes. As of April 24, 2013, holders of approximately 58% of the $300 million total principal amount of the 2016 Senior Notes outstanding had tendered their 2016 Senior Notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered by April 24, 2013 was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. On April 25, 2013, we paid a total of approximately $191 million, including accrued interest of $6.5 million for the 2016 Senior Notes tendered. On May 6, 2013, we made an irrevocable election in connection with the Redemption to redeem on May 10, 2013 the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We will pay a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes in connection with the Redemption. We will recognize a loss on the extinguishment of debt of approximately $29 million in connection with the Tender Offer and the Redemption, which will be recorded in the second quarter of 2013.


22



Issuance of 2020 Senior Notes

On April 24, 2013, we completed a private placement of $775 million of our 2020 Senior Notes. The 2020 Senior Notes were priced at par and interest will be payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by all of our material subsidiaries, or Guarantor Subsidiaries. Approximately $380 million of the net proceeds from the private placement, together with the Shares, were used to finance the Acquisition, including purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the revolving credit facility, or the Revolver, and to fund a portion of the Tender Offer and the Redemption.

Commodity Hedging Activities
 
For the remainder of 2013, we have approximately 65 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $94.38 and $96.58 per barrel. For 2014, we have approximately 35 to 40 percent of our estimated oil production hedged at a weighted-average swap price of $93.27 per barrel. These estimates include our anticipated oil production from the producing properties acquired in the Acquisition as well as properties that are expected to be developed.

For the remainder of 2013, we have approximately 70 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.77 and $4.13 per MMBtu. For 2014, we have approximately 21 percent of our estimated natural gas production hedged at a weighted-average floor/swap and ceiling prices of $4.03 and $4.11 per MMBtu. Similar to oil, these estimates include the Acquisition properties' production and 2013 future development. We do not have any NGLs hedged.

23




 Results of Operations

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012
 
Production
 
The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented: 
Crude oil
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
% Change
 
(MBbl)
 
 
 
(Bbl per day)
 
 
 
 
Texas
 
 
 
 


 

 

 


 


South Texas
529.9

 
460.1

 
69.8

 
5,887.7

 
5,056.5

 
831.2

 
15
 %
East Texas
16.6

 
19.1

 
(2.5
)
 
184.4

 
209.9

 
(25.5
)
 
(13
)%
Mid-Continent
48.3

 
65.1

 
(16.8
)
 
536.4

 
715.1

 
(178.7
)
 
(26
)%
Mississippi
4.0

 
4.0

 

 
44.9

 
44.2

 
0.7

 
 %
Appalachia
0.1

 
0.2

 
(0.1
)
 
1.5

 
2.6

 
(1.1
)
 
(43
)%
 
598.9

 
548.6

 
50.4

 
6,654.9

 
6,028.3

 
626.6

 
9
 %
NGLs
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
% Change
 
(MBbl)
 
 
 
(Bbl per day)
 
 
 
 
Texas
 
 
 
 


 

 

 


 


South Texas
80.0

 
33.6

 
46.4

 
888.7

 
369.3

 
0.5

 
138
 %
East Texas
65.1

 
72.7

 
(7.6
)
 
723.6

 
799.3

 
(0.1
)
 
(10
)%
Mid-Continent
89.0

 
108.3

 
(19.3
)
 
988.5

 
1,189.6

 
(0.2
)
 
(18
)%
Mississippi

 

 

 

 

 

 
 %
Appalachia

 
0.2

 
(0.2
)
 

 
2.0

 

 
(100
)%
 
234.1

 
214.8

 
19.3

 
2,600.9

 
2,360.2

 
240.7

 
9
 %
 
Natural gas
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
% Change
 
(MMcf)
 
 
 
(MMcf per day)
 
 
 
 
Texas
 
 
 
 


 


 


 


 


South Texas
403

 
183

 
220

 
4.5

 
2.0

 
2.5

 
120
 %
East Texas
1,170

 
1,647

 
(477
)
 
13.0

 
18.1

 
(5.1
)
 
(29
)%
Mid-Continent
804

 
1,108

 
(304
)
 
8.9

 
12.2

 
(3.2
)
 
(27
)%
Mississippi
1,151

 
1,293

 
(142
)
 
12.8

 
14.2

 
(1.4
)
 
(11
)%
Appalachia
35

 
2,062

 
(2,027
)
 
0.4

 
22.7

 
(22.3
)
 
(98
)%
 
3,565

 
6,294

 
(2,729
)
 
39.6

 
69.2

 
(29.6
)
 
(43
)%
Combined total
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
% Change
 
(MBOE)
 
 
 
(BOE per day)
 
 
 
 
Texas

 


 


 

 

 


 


South Texas
677

 
524

 
153

 
7,523.5

 
5,761.1

 
1,762.4

 
29
 %
East Texas
277

 
366

 
(90
)
 
3,075.4

 
4,026.3

 
(950.9
)
 
(25
)%
Mid-Continent
271

 
358

 
(87
)
 
3,014.6

 
3,934.4

 
(919.8
)
 
(24
)%
Mississippi
196

 
220

 
(24
)
 
2,176.9

 
2,413.0

 
(236.1
)
 
(11
)%
Appalachia
6

 
344

 
(338
)
 
66.9

 
3,781.6

 
(3,714.7
)
 
(98
)%
 
1,427

 
1,812

 
(385
)
 
15,857.3

 
19,916.4

 
(4,059.1
)
 
(21
)%
Certain results in the tables above may not calculate due to rounding.
 
 
 
 
 
 
 
 

The decline in total production during the three months ended March 31, 2013 compared to the corresponding period of 2012 was due primarily to the effect of the sale of our Appalachian Basin natural gas properties in July 2012 and production declines in our East Texas and Mid-Continent regions. The effect of the sale of the Appalachian properties was approximately 321 million barrels of oil equivalent, or MBOE. The declines in production from our remaining natural gas properties were partially offset by an increase in oil, NGL and natural gas production attributable to our drilling activity in the Eagle Ford Shale.

24



Approximately 58% of total production during the three months ended March 31, 2013 was attributable to oil and NGLs, which represents an increase of approximately 39% over the prior year period. During the three months ended March 31, 2013, our Eagle Ford Shale production represented approximately 47% of our total production as compared to approximately 29% from this play during the corresponding period during 2012.

Product Revenues and Prices
 
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:
Crude oil
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
 
 
 
 
 
 
($ per Bbl)
 
 
Texas
 
 
 
 


 
 
 
 
 


Eagle Ford Shale
$
56,665

 
$
49,844

 
$
6,821

 
$
106.94

 
$
108.32

 
$
(1.38
)
East Texas
1,636

 
1,945

 
(309
)
 
98.55

 
101.83

 
(3.28
)
Mid-Continent
4,311

 
6,464

 
(2,153
)
 
89.30

 
99.33

 
(10.03
)
Mississippi
432

 
448

 
(16
)
 
106.96

 
111.44

 
(4.48
)
Appalachia
14

 
22

 
(8
)
 
102.19

 
91.67

 
10.52

 
$
63,058

 
$
58,723

 
$
4,335

 
$
105.28

 
$
107.05

 
$
(1.77
)
NGLs
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
 
 
 
 
 
 
($ per Bbl)
 
 
Texas
 
 
 
 


 
 
 
 
 


Eagle Ford Shale
$
1,995

 
$
1,473

 
$
522

 
$
24.94

 
$
43.83

 
$
(18.89
)
East Texas
1,796

 
3,302

 
(1,506
)
 
27.58

 
45.40

 
(17.82
)
Mid-Continent
3,336

 
4,285

 
(949
)
 
37.50

 
39.58

 
(2.08
)
Mississippi

 

 

 

 

 

Appalachia

 
11

 
(11
)
 

 
60.11

 
(60.11
)
 
$
7,127

 
$
9,071

 
$
(1,944
)
 
$
30.45

 
$
42.24

 
$
(11.79
)
Natural gas
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
 
 
 
 
 
 
($ per Mcfe)
 
 
Texas
 
 
 
 


 
 
 
 
 


Eagle Ford Shale
$
1,280

 
$
422

 
$
858

 
$
3.17

 
$
2.30

 
$
0.87

East Texas
3,574

 
3,811

 
(237
)
 
3.05

 
2.31

 
0.74

Mid-Continent
2,535

 
1,535

 
1,000

 
3.15

 
1.39

 
1.76

Mississippi
4,512

 
3,695

 
817

 
3.92

 
2.86

 
1.06

Appalachia
138

 
5,423

 
(5,285
)
 
3.91

 
2.63

 
1.28

 
$
12,039

 
$
14,886

 
$
(2,847
)
 
$
3.38

 
$
2.37

 
$
1.01

Combined total
Three Months Ended March 31,
 
Favorable
 
Three Months Ended March 31,
 
Favorable
 
2013
 
2012
 
(Unfavorable)
 
2013
 
2012
 
(Unfavorable)
 
 
 
 
 
 
 
($ per BOE)
 
 
Texas


 
 
 


 
 
 
 
 


Eagle Ford Shale
$
59,940

 
$
51,739

 
$
8,201

 
$
88.52

 
$
98.69

 
$
(10.17
)
East Texas
7,006

 
9,058

 
(2,052
)
 
25.31

 
24.72

 
0.59

Mid-Continent
10,182

 
12,284

 
(2,102
)
 
37.53

 
34.31

 
3.22

Mississippi
4,944

 
4,143

 
801

 
25.23

 
18.87

 
6.36

Appalachia
152

 
5,456

 
(5,304
)
 
25.26

 
15.85

 
9.41

 
$
82,224

 
$
82,680

 
$
(456
)
 
$
57.61

 
$
45.62

 
$
11.99


As illustrated below, higher oil and NGL production volume coupled with improved natural gas prices were essentially offset by the overall decline in oil and NGL prices and lower natural gas production volume attributable to the sale of our Appalachian properties. Included in the price variance for natural gas was approximately $0.2 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the Mid-Continent region.


25



The following table provides an analysis of the change in our revenues for the three months ended March 31, 2013 as compared to the three months ended March 31, 2012:
 
Revenue Variance Due to
 
Volume
 
Price
 
Total
Crude oil
$
5,391

 
$
(1,056
)
 
$
4,335

NGL
815

 
(2,759
)
 
(1,944
)
Natural gas
(6,455
)
 
3,608

 
(2,847
)
 
$
(249
)
 
$
(207
)
 
$
(456
)
 
Effects of Derivatives
 
Our oil and gas 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 oil and gas prices. In the three months ended March 31, 2013 and 2012, we received $3.6 million and $8.0 million, respectively, in cash settlements of oil and gas derivatives.
 
The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented: 
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Crude oil revenues as reported
$
63,058

 
$
58,723

 
$
4,335

 
7
 %
Cash settlements on crude oil derivatives, net
2,809

 
(107
)
 
2,916

 
NM

Crude oil revenues adjusted for derivatives
$
65,867

 
$
58,616

 
$
7,251

 
12
 %
 
 
 
 
 
 
 
 
Crude oil prices per Bbl, as reported
$
105.28

 
$
107.05

 
$
(1.76
)
 
(2
)%
Cash settlements on crude oil derivatives per Bbl
4.69

 
(0.20
)
 
4.89

 
NM

Crude oil prices per Bbl adjusted for derivatives
$
109.97

 
$
106.85

 
$
3.12

 
3
 %
 
 
 
 
 
 
 
 
Natural gas revenues as reported
$
12,039

 
$
14,886

 
$
(2,847
)
 
(19
)%
Cash settlements on natural gas derivatives, net
748

 
8,088

 
(7,340
)
 
(91
)%
Natural gas revenues adjusted for derivatives
$
12,787

 
$
22,974

 
$
(10,187
)
 
(44
)%
 
 
 
 
 
 
 
 
Natural gas prices per Mcf, as reported
$
3.38

 
$
2.37

 
$
1.01

 
43
 %
Cash settlements on natural gas derivatives per Mcf
0.21

 
1.28

 
(1.08
)
 
(84
)%
Natural gas prices per Mcf adjusted for derivatives
$
3.59

 
$
3.65

 
$
(0.06
)
 
(2
)%
NM - Not meaningful
 
 
 
 
 
 
 
 
(Loss) Gain on Sales of Property and Equipment
 
In the three months ended March 31, 2013, we recognized a loss on the assignment of certain properties in West Virginia associated with our 2012 sale of legacy natural gas assets that was not completed until January 2013. In the three months ended March 31, 2012, we recognized a gain attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong Counties, Pennsylvania. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well material during both periods.
 
Other Income
 
Other income, which includes ancillary gathering, transportation, compression and water disposal fees and other miscellaneous operating income net of marketing and related expenses, increased during the three months ended March 31, 2013 due primarily to the sale of certain seismic data partially offset by expense attributable to our firm transportation obligation in the Appalachian region.

26



Production and Lifting Costs
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Lease operating
$
7,805

 
$
9,143

 
$
1,338

 
15
 %
Per unit of production ($/BOE)
$
5.47

 
$
5.05

 
$
(0.42
)
 
(8
)%

Lease operating expense decreased on an absolute basis during the three months ended March 31, 2013 due primarily to the effect of the sale of our higher-cost Appalachian Basin properties in July 2012. The sale-related cost decreases were more than offset by higher paraffin and corrosion inhibitor chemical costs associated with our increased oil production as well as higher environmental permitting and certain facility and tank battery maintenance costs.

 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Gathering, processing and transportation
$
3,579

 
$
4,154

 
$
575

 
14
 %
Per unit of production ($/BOE)
$
2.51

 
$
2.29

 
$
(0.22
)
 
(10
)%

Gathering, processing and transportation charges decreased during the three months ended March 31, 2013, due primarily to the effect of the sale of our Appalachian Basin properties in July 2012 partially offset by higher processing costs associated with NGLs in the Eagle Ford Shale in Lavaca County as compared to the corresponding period of 2012.
 
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Production and ad valorem taxes
$
5,959

 
$
3,580

 
$
(2,379
)
 
(66
)%
Per unit of production ($/BOE)
$
4.18

 
$
1.98

 
$
(2.20
)
 
(111
)%
Tax rate as a percent of product revenue
7.2
%
 
4.3
%
 
 
 
 
 
Production and ad valorem taxes increased during the 2013 period due primarily to our expanding presence in the Eagle Ford Shale in South Texas.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Recurring general and administrative expenses
$
9,844

 
$
10,457

 
$
613

 
6
 %
Share-based compensation (liability-classified)
14

 
72

 
58

 
81
 %
Share-based compensation (equity-classified)
1,085

 
1,615

 
530

 
33
 %
Restructuring expenses

 
(3
)
 
(3
)
 
(100
)%
 
$
10,943

 
$
12,141

 
$
1,198

 
10
 %
Per unit of production ($/BOE)
$
7.67

 
$
6.70

 
$
(0.97
)
 
(14
)%
Per unit of production excluding share-based compensation
 
 
 
 
 
 
 
and restructuring charges ($/BOE)
$
6.91

 
$
5.81

 
$
(1.10
)
 
(19
)%
  
Recurring general and administrative expenses decreased due to reduced headcount and lower support costs following the sale of our Appalachian Basin properties in July 2012. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, issued in 2012, which are payable in cash in 2015 upon achievement of specified 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 three months ended March 31, 2013 due primarily to the deferral of 2013 grants to certain officers until approval was received from shareholders on May 1, 2013 for an amendment to our stock compensation plan.

27



Exploration
 
The following table sets forth the components of exploration expenses for the periods presented:
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Unproved leasehold amortization
$
5,262

 
$
8,171

 
$
2,909

 
36
%
Geological and geophysical costs
980

 
(423
)
 
(1,403
)
 
NM

Other, primarily delay rentals
53

 
250

 
197

 
79
%
 
$
6,295

 
$
7,998

 
$
1,703

 
21
%

Unproved leasehold amortization declined during the three months ended March 31, 2013 as costs related to successful Eagle Ford Shale wells were transferred to proved properties. Geological and geophysical costs increased during the 2013 period due primarily to a recoupment from certain of our joint venture partners during the 2012 period of amounts expended in prior periods.
 
Depreciation, Depletion and Amortization (DD&A)
 
The following table sets forth the nature of the DD&A variances for the periods presented:
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
DD&A expense
$
51,576

 
$
50,817

 
$
(759
)
 
(1
)%
DD&A rate ($/BOE)
$
36.14

 
$
28.04

 
$
(8.10
)
 
(29
)%
 
 
 
 
 
 
 
 
 
Production
 
Rates
 
Total
 
 
DD&A variance due to:
$
10,810

 
$
(11,569
)
 
$
(759
)
 
 
  
The effect of lower overall production volumes on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average DD&A rate increased due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale.
 
Interest Expense
 
The following table summarizes the components of our interest expense for the periods presented:
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Interest on borrowings and related fees
$
13,583

 
$
14,017

 
$
434

 
3
 %
Accretion of original issue discount
321

 
333

 
12

 
4
 %
Amortization of debt issuance costs
626

 
682

 
56

 
8
 %
Capitalized interest
(51
)
 
(258
)
 
(207
)
 
(80
)%
 
$
14,479

 
$
14,774

 
$
295

 
2
 %
Weighted-average debt outstanding
$
619,678

 
$
706,739

 
 
 
 
Weighted average interest rate
9.35
%
 
8.36
%
 
 
 
 
 
Interest expense decreased due primarily to a lower average outstanding principal balance on the Revolver during the three months ended March 31, 2013 despite higher effective interest rates attributable to our fixed rate senior notes. Capitalized interest was lower during the 2013 period due to lower carrying values on eligible capital projects.
 

28



Derivatives
 
The following table summarizes the components of our derivatives income for the periods presented:
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Oil and gas derivative realized gain
$
3,557

 
$
7,981

 
$
(4,424
)
 
(55
)%
Oil and gas derivative unrealized loss
(11,318
)
 
(7,687
)
 
(3,631
)
 
(47
)%
Interest rate swap unrealized loss

 
(599
)
 
599

 
100
 %
 
$
(7,761
)
 
$
(305
)
 
$
(7,456
)
 
NM

  
We received cash settlements of $3.6 million during the three months ended March 31, 2013 and $8.0 million during the three months ended March 31, 2012. The increase in the unrealized loss on commodity derivatives was due primarily to oil and natural gas prices closing at period end above our hedged prices on an aggregate basis.

Other
 
Other income increased during the three months ended March 31, 2013 due primarily to income earned from a vendor account processing bonus.

Income Taxes
 
Three Months Ended
 
 
 
 
 
March 31,
 
Favorable
 
 
 
2013
 
2012
 
(Unfavorable)
 
% Change
Income tax benefit
$
8,789

 
$
6,601

 
$
2,188

 
33
%
Effective tax benefit rate
34.9
%
 
35.7
%
 
 
 
 

Due to the operating losses incurred, we recognized an income tax benefit during both periods. The effective tax benefit rate for the three months ended March 31, 2013 and 2012 included a deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.


29



 Liquidity and Capital Resources
 
Sources of Liquidity
 
Our business strategy contemplates capital expenditures in excess of our projected operating cash flows for 2013. 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 2013 capital program with operating cash flows and borrowings under the Revolver. Excluding the 2016 Senior Notes, which will be redeemed in their entirety by May 10, 2013 in connection with the Tender Offer and the Redemption, we have no debt maturities until September 2017 when the Revolver matures.

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 by up to an additional aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver is governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver was $300 million and will be re-determined by the end of May 2013, and semi-annually thereafter, based on a review of our total proved oil, NGL and natural gas reserves. Subsequent to the private placement of the 2020 Senior Notes, our borrowing base under the Revolver was reduced by $23.8 million to $276.2 million. We anticipate the borrowing base will be increased to a level within a range from $320 million to $350 million in connection with the May 2013 re-determination.

As of May 3, 2013, we had $273.4 million of unused borrowing capacity available to us under the Revolver. The borrowing capacity is determined by reducing the current borrowing base of $276.2 million by outstanding letters of credit of $2.8 million. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions.

The following table summarizes our borrowing activity under the Revolver during the period presented:
 
Borrowings Outstanding
 
 
 
Weighted-
Average
 
Maximum
 
Weighted-
Average Rate
Three months ended March 31, 2013
$
23,567

 
$
38,000

 
1.7500
%

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 on our cash flow at risk, available hedge prices and our operating strategy. During the three months ended March 31, 2013, our commodity derivatives portfolio provided $2.8 million of cash inflows related to lower than anticipated prices received for our oil production and $0.7 million of cash inflows attributable to lower than anticipated prices received for our natural gas production.
 
For the remainder of 2013, we have hedged approximately 65 percent of our estimated crude oil production, at weighted average floor/swap and ceiling prices of between $94.38 and $96.58 per barrel. In addition, we have hedged approximately 70 percent of our estimated natural gas production for 2013, at weighted average floor/swap and ceiling prices of between $3.77 and $4.13 per MMBtu.





30



Cash Flows
 
The following table summarizes our statements of cash flows for the periods presented:
 
Three Months Ended
 
 
 
March 31,
 
 
 
2013
 
2012
 
Variance
Cash flows from operating activities
 
 
 
 


Operating cash flows, net
$
42,295

 
$
42,723

 
$
(428
)
Working capital changes, net
601

 
20,351

 
(19,750
)
Commodity derivative settlements received, net:
 
 
 
 

Crude oil
2,809

 
(107
)
 
2,916

Natural gas
748

 
8,088

 
(7,340
)
Interest payments, net of amounts capitalized
(340
)
 
(557
)
 
217

Income tax refunds received (payments made), net

 
301

 
(301
)
Restructuring and exit costs paid
(498
)
 
(98
)
 
(400
)
Net cash provided by operating activities
45,615

 
70,701

 
(25,086
)
Cash flows from investing activities
 

 
 

 
 

Capital expenditures -  property and equipment
(85,973
)
 
(94,469
)
 
8,496

Proceeds from sales of assets and other, net
878

 
778

 
100

Net cash used in investing activities
(85,095
)
 
(93,691
)
 
8,596

Cash flows from financing activities
 

 
 

 
 

Proceeds from revolving credit facility borrowings, net
38,000

 
20,000

 
18,000

Dividends paid on preferred and common stock
(1,687
)
 
(2,586
)
 
899

Other, net
(61
)
 

 
(61
)
Net cash provided by financing activities
36,252

 
17,414

 
18,838

Net increase (decrease) in cash and cash equivalents
$
(3,228
)
 
$
(5,576
)
 
$
2,348

 
Cash Flows From Operating Activities
  
Due primarily to the timing of disbursements and a higher level of accounts payable settled during the 2013 period, our cash flows from operating activities declined during the three months ended March 31, 2013 as compared to the corresponding period during 2012. In addition, we realized lower settlements from our commodity derivatives portfolio during the 2013 period as compared to the corresponding period during 2012 due primarily to a significantly lower volume of natural gas production subject to hedges. Restructuring and exit costs paid were higher during the 2013 period as compared to the corresponding period of 2012 due primarily to ongoing contractual payments for firm transportation capacity in the Appalachian region subsequent to our 2012 sale of assets in that region. Realized cash flows from higher operating margin oil and NGL operations were essentially offset by the absence of natural gas production from the divested Appalachian assets. These decreases in operating cash flows were slightly offset by lower amounts paid for interest during the 2013 period due to lower average outstanding Revolver balances.

Cash Flows From Investing Activities

Capital expenditures were lower during the three months ended March 31, 2013 as compared to the corresponding period during 2012 due primarily to the timing of disbursements and settlements of accrued capital costs attributable to our Eagle Ford Shale drilling program.

Proceeds from sales of non-core properties and other assets were received during both the 2013 and 2012 periods. The amounts received during the 2013 period were attributable primarily to the assignment of certain properties in West Virginia, associated with our 2012 sale of legacy natural gas assets that was not completed until January 2013. The amounts received during the 2012 period were attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong Counties, Pennsylvania.
 

31



The following table sets forth costs related to our capital expenditure program for the periods presented:
 
Three Months Ended
 
March 31,
 
2013
 
2012
Oil and gas:
 

 
 

Development drilling
$
75,428

 
$
61,440

Exploration drilling
11,120

 
21,152

Geological and geophysical (seismic) costs
980

 
(423
)
Lease acquisitions
4,997

 
4,344

Pipeline, gathering facilities and other
2,958

 
3,901

 
95,483

 
90,414

Other - Corporate
116

 
66

Total capital program costs
$
95,599

 
$
90,480

 
The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:
 
Three Months Ended
 
March 31,
 
2013
 
2012
Total capital program costs
$
95,599

 
$
90,480

Less:
 
 
 
Exploration expenses
 
 
 
Geological and geophysical (seismic)
(980
)
 
423

Other, primarily delay rentals
(53
)
 
(199
)
Transfers from tubular inventory and well materials
(736
)
 
(6,081
)
Changes in accrued capitalized costs
(7,921
)
 
9,588

Add:
 

 
 

Tubular inventory and well materials purchased in advance of drilling
13

 

Capitalized interest
51

 
258

Total cash paid for capital expenditures
$
85,973

 
$
94,469


Cash Flows From Financing Activities

Cash flows from financing activities for both the three months ended March 31, 2013 and 2012 include borrowings under the Revolver. The 2013 period includes dividends paid on our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock, and the 2012 period includes dividends paid on our common stock.


32



Financial Condition
 
As of May 3, 2013, we had $273.4 million of unused borrowing capacity available to us under the Revolver. The borrowing capacity is determined by reducing the current borrowing base of $276.2 million by outstanding letters of credit of $2.8 million. The indentures for our Senior Notes include an incurrence test which could potentially limit our ability to issue additional debt if our interest coverage ratio, as defined in the indentures, exceeds 2.25 times consolidated EBITDAX, a non-GAAP measure. Our actual interest coverage ratio for the twelve month period ended March 31, 2013 was 3.86.
 
Debt and Credit Facilities and Preferred Stock Financing
 
Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, 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 charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of May 3, 2013, the actual interest rate applicable to the Revolver was 1.75%.
 
The Revolver is guaranteed by Penn Virginia and the Guarantor Subsidiaries. The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.
 
2016 Senior Notes. The 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 in June 2009, 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.

2020 Senior Notes. The 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on May 1 and November 1 of each year. The 2020 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 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.
  
6% Preferred Stock. The annual dividend on each share of the 6% Preferred Stock is 6.00% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each of January 15, April 15, July 15 and October 15 of each year. We may, at our option, pay dividends in cash, common stock or a combination thereof.

Each share of the 6% Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $6.00 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the 6% Preferred Stock. The initial conversion price represents a premium of 20 percent relative to the 2012 common stock offering price of $5.00 per share. The 6% Preferred Stock is not redeemable by us or the holders at any time. At any time on or after October 15, 2017, we may, at our option, cause all outstanding shares of the 6% Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the 6% Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.


33



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 for periods through December 31, 2013, 4.25 to 1.0 for periods through June 30, 2014 and 4.0 to 1.0 for periods through maturity in 2017. 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 March 31, 2013 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 as of and for the period ended March 31, 2013:
 
 
Required
 
Actual
Description of Covenant
 
Covenant
 
Results
Total debt to EBITDAX
 
< 4.5 to 1
 
2.6 to 1
Current ratio
 
> 1.0 to 1
 
2.8 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 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 2013, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $505 million. The capital expenditures for 2013 will be funded primarily by operating cash flows and borrowings under the Revolver. 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 2013, we expect to allocate capital expenditures as follows: Eagle Ford Shale (approximately 94 percent) and Mid-Continent region and all other areas (approximately 6 percent). This allocation includes approximately 89 percent for drilling and completions, 6 percent for leasehold acquisition and 5 percent for pipeline 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 that 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 form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of March 31, 2013, we have recorded asset retirement obligations of $4.6 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

34



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 regulations or the adoption of new environmental laws or regulations, 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, 2012.

 New Accounting Standards
 
During the three months ended March 31, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 11 to the Condensed Consolidated Financial Statements. The adoption of ASU 2013-02 did not have a significant impact on our Condensed Consolidated Financial Statements and Notes to the Condensed Consolidated Financial Statements.

35




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. 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 March 31, 2013, we had borrowings of $38 million under the Revolver at an interest rate of 1.75%. Assuming a constant borrowing level of $38 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 $0.4 million on an annual basis.
 
Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. 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 commodity 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 oil and natural gas. We have not typically entered into derivative instruments with respect to NGLs, although we may do so in the future.
 
As of March 31, 2013, we reported a commodity derivative asset of $9.5 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 neither paid nor received collateral with respect to our derivative 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 March 31, 2013.
 
During the three months ended March 31, 2013, we reported net commodity derivative losses of $7.8 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 crude oil, NGL and natural gas 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.
 

36



The following table sets forth our commodity derivative positions as of March 31, 2013:
 
 
 
Average
 
 
 
 
 
 
 
 
 
Volume Per
 
Weighted Average Price
 
Fair Value
 
Instrument
 
Day
 
Floor/Swap
 
Ceiling
 
Asset
 
Liability
Crude Oil:
 
 
(barrels)
 
($/barrel)
 
 
 
 
Second quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 
$

 
$
164

Third quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 

 
235

Fourth quarter 2013
Collars
 
1,900

 
$
90.00

 
$
99.17

 

 
81

Second quarter 2013
Swaps
 
3,750

 
$
101.26

 
 
 
1,460

 
173

Third quarter 2013
Swaps
 
4,000

 
$
98.43

 
 
 
1,038

 
550

Fourth quarter 2013
Swaps
 
4,000

 
$
98.43

 
 
 
1,355

 
357

First quarter 2014
Swaps
 
4,000

 
$
95.27

 
 

 
1,093

 
720

Second quarter 2014
Swaps
 
4,000

 
$
95.27

 
 

 
1,312

 
519

Third quarter 2014
Swaps
 
3,500

 
$
94.43

 
 

 
1,096

 
347

Fourth quarter 2014
Swaps
 
3,500

 
$
94.43

 
 

 
1,199

 
210

First quarter 2014
Swaption
 
1,812

 
$
100.00

 
 

 

 
281

Second quarter 2014
Swaption
 
1,812

 
$
100.00

 
 

 

 
280

Third quarter 2014
Swaption
 
1,812

 
$
100.00

 
 

 

 
280

Fourth quarter 2014
Swaption
 
1,812

 
$
100.00

 
 

 

 
280

 
 
 
 
 
 
 
 
 
 
 
 
Natural Gas:
 
 
(in MMBtu)

 
($/MMBtu)
 
 

 
 
Second quarter 2013
Collars
 
10,000

 
$
3.50

 
4.30

 

 
34

Third quarter 2013
Collars
 
10,000

 
$
3.50

 
4.30

 

 
125

Fourth quarter 2013
Collars
 
15,000

 
$
3.67

 
4.37

 
15

 
222

First quarter 2014
Collars
 
5,000

 
$
4.00

 
4.50

 

 
58

Second quarter 2013
Swaps
 
15,000

 
$
3.92

 
 

 
13

 
151

Third quarter 2013
Swaps
 
15,000

 
$
3.92

 
 

 

 
271

Fourth quarter 2013
Swaps
 
10,000

 
$
4.04

 
 

 

 
160

First quarter 2014
Swaps
 
5,000

 
$
4.05

 
 
 

 
145

Second quarter 2014
Swaps
 
10,000

 
$
4.03

 
 
 

 
53

Third quarter 2014
Swaps
 
10,000

 
$
4.03

 
 
 

 
105

Settlements to be received in subsequent period
 
 
 

 
 

 
 

 
954

 


The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil prices, natural gas 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 $10.00 per Bbl of  Crude Oil
or $1.00 per MMBtu of Natural Gas
($ in millions)
 
Increase

 
Decrease

Effect on the fair value of crude oil derivatives
$
(33.0
)
 
$
27.5

Effect on the fair value of natural gas derivatives
$
(8.0
)
 
$
7.7

 
 
 
 
Effect on 2013 operating income, excluding crude oil derivatives
$
32.1

 
$
(32.1
)
Effect on 2013 operating income, excluding natural gas derivatives
$
10.3

 
$
(10.3
)

37




 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 our 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 March 31, 2013. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, 2013, 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 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

38




Part II. OTHER INFORMATION
Item 1A
Risk Factors

There have been no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012 except for the addition of the following:

We have a significant amount of indebtedness and our ability to service our indebtedness depends on certain financial, business and other factors, many of which are beyond our control.

After giving effect to the Acquisition, the issuance of $775 million of our 2020 Senior Notes and the consummation of the Tender Offer and Redemption, as of March 31, 2013, we would have had approximately $1,075 million of debt outstanding and the ability to incur an additional approximately $273.4 million (net of $2.8 million letters of credit) under the Revolver. The increase in our indebtedness may reduce our flexibility to respond to changing business and economic conditions or to fund capital expenditures or working capital needs.

We and our subsidiaries may incur additional indebtedness in the future. Subject to certain conditions, the terms of our existing debt instruments do not prohibit us or our subsidiaries from incurring additional indebtedness. Any increase in our level of indebtedness may have several important effects on our future operations, including without limitation:

we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry condition, as well as to competitive pressure; and

depending on the levels of our outstanding debt, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

Our ability to make scheduled payments of principal and interest on our indebtedness or to refinance our debt obligations depends on our future financial condition and operating performance, which will be subject to general economic conditions and to certain financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flows from operations in the future to service our debt, we may be forced, among other things to:

sell selected assets;

reduce or delay planned capital expenditures;

refinance or restructure all or a portion of our indebtedness;

seek additional financing in the debt or equity markets; or

reduce or delay planned operating expenditures.

Such measures might not be successful, might not be available on economically favorable terms and might not enable us to service our debt.

39



Item 6
Exhibits
(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 3, 2013).
 
 
(4.1)
Senior Indenture, dated June 15, 2009, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2009).
 
 
(4.2)
Fourth Supplemental Indenture relating to the 8.500% Senior Notes due 2020, dated April 14, 2013, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
 
 
(4.3)
Form of 8.500% Senior Notes due 2020 (incorporated by reference to Exhibit 1 to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
 
 
(4.4)
Registration Rights Agreement, dated April 24, 2013, among Penn Virginia Corporation, the several guarantors named therein and RBC Capital Markets, LLC, as representatives of the initial purchasers named therein (incorporated by reference to Exhibit 4.4 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
 
 
(4.5)
Registration Rights, Lock-Up and Buy-Back Agreement, dated April 24, 2013, between Penn Virginia Corporation and Magnum Hunter Resources Corporation (incorporated by reference to Exhibit 4.5 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
 
 
(4.6)
Fifth Supplemental Indenture relating to the 10.375% Senior Notes due 2016, dated April 24, 2013, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.6 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
 
 
(10.1)
Executive Change of Control Severance Agreement dated January 29, 2013 by and between Penn Virginia Corporation and John A. Brooks (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 1, 2013).
 
 
(10.2)
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 February 7, 2013).
 
 
(12.1)
Statement of Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Calculation.
 
 
(31.1)
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
(31.2)
Certification Pursuant to 18 U.S.C. Section 1350, 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
 

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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
 
 
 
By:
/s/ STEVEN A. HARTMAN
 
 
Steven A. Hartman 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
May 8, 2013
By: 
/s/ JOAN C. SONNEN
 
 
Joan C. Sonnen 
 
 
Vice President and Controller

  


   



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