petro.dev-10Q-1Q12
Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

or

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to _________

Commission File Number 000-07246
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
(Doing Business as PDC Energy)
Nevada
95-2636730
(State of Incorporation)
(I.R.S. Employer Identification No.)
1775 Sherman Street, Suite 3000
Denver, Colorado 80203
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (303) 860-5800

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 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 T No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T 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 definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer  £
Accelerated filer  x
Non-accelerated filer  £
(Do not check if a smaller reporting company)
Smaller reporting company  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No T

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 23,665,459 shares of the Company's Common Stock ($0.01 par value) were outstanding as of April 20, 2012.





Table of Contents

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

TABLE OF CONTENTS

 
PART I - FINANCIAL INFORMATION
 
Page
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
Item 3.
 
Item 4.
 
 
 
 
 
PART II – OTHER INFORMATION
 
 
 
 
Item 1.
 
Item 1A.
 
Item 2.
 
Item 3.
 
Item 4.
 
Item 5.
 
Item 6.
 
 
 
 
 
 
 



Table of Contents

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements include: estimated natural gas, natural gas liquids ("NGLs") and crude oil production; future production levels and expenses, anticipated capital expenditures, including our ability to fund our 2012 capital budget; increased focus on the Wattenberg Field and liquid-rich areas and pursuing strategic and complementary acquisitions in Niobrara and Utica; our compliance with our debt covenants and the indenture restrictions governing our senior notes and expected continued compliance; the adequacy of our casualty insurance coverage as managing general partner of numerous partnerships and as operator of our own wells; the impact of decreased commodity prices on future borrowing base redeterminations; the effectiveness of our derivative policies in achieving our risk management objectives; the sufficiency of our monitoring procedures for the credit worthiness of our financial institutions; our expected remaining liability for uncertain tax positions; our ability to secure a joint venture partner for our Utica Shale acreage; the impact of outstanding legal issues; our ability to meet our partnership repurchase obligations, if applicable; our ability to benefit from crude oil and natural gas price differentials; and our strategies, plans and objectives.

The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:
changes in production volumes and worldwide demand, including economic conditions that might impact demand;
volatility of commodity prices for natural gas, NGLs and crude oil;
the impact of governmental fiscal terms and/or regulations, including changes in environmental laws, the regulation and enforcement related to those laws and the costs to comply with those laws, as well as other regulations;
decline in the values of our natural gas and crude oil properties resulting in impairments;
changes in estimates of proved reserves;
inaccuracy of reserve estimates and expected production rates;
the potential for production decline rates from our wells to be greater than expected;
the timing and extent of our success in discovering, acquiring, developing and producing reserves;
our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
the timing and receipt of necessary regulatory permits;
risks incidental to the drilling and operation of natural gas and crude oil wells;
our future cash flow, liquidity and financial position;
competition in the oil and gas industry;
the availability and cost of capital to us;
reductions in the borrowing base under our credit facility;
the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
our success in marketing natural gas, NGLs and crude oil;
the effect of natural gas and crude oil derivatives activities;
the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events;
the cost of pending or future litigation;
the effect that acquisitions we may pursue have on our capital expenditures;
our ability to retain or attract senior management and key technical employees; and
the success of strategic plans, expectations and objectives for future operations of the Company.
 
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in this report, our annual report on Form 10-K for the year ended December 31, 2011, filed with the United States Securities and Exchange Commission ("SEC") on March 1, 2012 ("2011 Form 10-K"), and our other filings with the SEC for further information on risks and uncertainties that could affect the Company's business, financial condition and results of operations, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.


3

Table of Contents

REFERENCES

Unless the context otherwise requires, references in this report to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, Petroleum Development Corporation, and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin ("Marcellus JV"). Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and the Marcellus JV's assets, results of operations, cash flows and operating activities.

See Note 1, Nature of Operations and Basis of Presentation, to our condensed consolidated financial statements included in this report for a description of our consolidated subsidiaries.

References to "the three months ended 2012" refer to the three months ended March 31, 2012, as applicable. References to "the three months ended 2011" refer to the three months ended March 31, 2011, as applicable.



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Table of Contents

PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS


PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Balance Sheets
(unaudited; in thousands, except share and per share data)
 
March 31, 2012
 
December 31, 2011 (1)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,655

 
$
8,238

Restricted cash
2,315

 
11,070

Accounts receivable, net
64,019

 
59,923

Accounts receivable affiliates
9,534

 
8,518

Fair value of derivatives
74,778

 
60,809

Prepaid expenses and other current assets
7,672

 
24,492

Total current assets
159,973

 
173,050

Properties and equipment, net
1,329,460

 
1,301,716

Assets held for sale

 
148,249

Fair value of derivatives
36,751

 
41,175

Accounts receivable affiliates
2,147

 
2,836

Other assets
37,238

 
30,979

Total Assets
$
1,565,569

 
$
1,698,005

 
 
 
 
Liabilities and Equity
 
 
 
Liabilities
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
56,152

 
$
76,027

Accounts payable affiliates
11,682

 
10,176

Production tax liability
19,170

 
18,949

Fair value of derivatives
30,513

 
27,974

Funds held for distribution
30,093

 
28,594

Accrued interest payable
5,069

 
11,243

Other accrued expenses
12,583

 
22,083

Total current liabilities
165,262

 
195,046

Long-term debt
414,809

 
532,157

Deferred income taxes
198,082

 
207,573

Asset retirement obligations
45,172

 
46,316

Fair value of derivatives
25,815

 
21,106

Accounts payable affiliates
5,207

 
6,134

Other liabilities
29,990

 
25,561

Total liabilities
884,337

 
1,033,893

 
 
 
 
Commitments and contingent liabilities

 

 
 
 
 
Shareholders' equity:
 
 
 
Preferred shares, par value $0.01 per share; authorized 50,000,000
shares; issued: none

 

Common shares, par value $0.01 per share; authorized 100,000,000
shares; issued: 23,659,339 in 2012 and 23,634,958 in 2011
237

 
236

Additional paid-in capital
219,139

 
217,707

Retained earnings
462,115

 
446,280

Treasury shares, at cost: 6,944 in 2012 and 2,938 in 2011
(259
)
 
(111
)
Total shareholders' equity
681,232

 
664,112

Total Liabilities and Equity
$
1,565,569

 
$
1,698,005

 
 
 
 
__________
(1) Derived from audited 2011 balance sheet.


See accompanying Notes to Condensed Consolidated Financial Statements
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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
 
Three Months Ended March 31,
 
2012
 
2011
Revenues:
 
 
 
Natural gas, NGL and crude oil sales
$
75,310

 
$
58,810

Sales from natural gas marketing
11,834

 
15,202

Commodity price risk management gain (loss), net
11,501

 
(23,882
)
Well operations, pipeline income and other
1,701

 
1,843

Total revenues
100,346

 
51,973

 
 
 
 
Costs, expenses and other:
 
 
 
Production costs
19,189

 
18,472

Cost of natural gas marketing
11,492

 
14,993

Exploration expense
2,063

 
1,669

Impairment of natural gas and crude oil properties
653

 
453

General and administrative expense
14,708

 
13,873

Depreciation, depletion and amortization
39,814

 
30,985

Gain on sale of properties and equipment
(154
)
 

Total costs, expenses and other
87,765

 
80,445

 
 
 
 
Income (loss) from operations
12,581

 
(28,472
)
Interest income
2

 
9

Interest expense
(10,444
)
 
(9,062
)
Income (loss) from continuing operations before income taxes
2,139

 
(37,525
)
 
 
 
 
Provision (benefit) for income taxes
759

 
(14,278
)
 
 
 
 
Income (loss) from continuing operations
1,380

 
(23,247
)
Income from discontinued operations, net of tax
14,455

 
3,323

Net income (loss)
$
15,835

 
$
(19,924
)
 
 
 
 
Earnings (loss) per share:
 
 
 
Basic
 
 
 
Income (loss) from continuing operations
$
0.06

 
$
(0.99
)
Income from discontinued operations
0.61

 
0.14

Net income (loss)
$
0.67

 
$
(0.85
)
Diluted
 
 
 
Income (loss) from continuing operations
$
0.06

 
$
(0.99
)
Income from discontinued operations
0.60

 
0.14

Net income (loss)
$
0.66

 
$
(0.85
)
 
 
 
 
Weighted average common shares outstanding
 
 
 
Basic
23,609

 
23,428

Diluted
23,889

 
23,428

 
 
 
 
 

See accompanying Notes to Condensed Consolidated Financial Statements
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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

 
Three Months Ended March 31,
 
2012
 
2011
Cash flows from operating activities:
 
 
 
Net income (loss)
$
15,835

 
$
(19,924
)
Adjustments to net income to reconcile to net cash provided by operating activities:
 
 
 
Unrealized (gain) loss on derivatives, net
(1,533
)
 
27,745

Depreciation, depletion and amortization
39,814

 
32,357

Impairment of natural gas and crude oil properties
653

 
453

Exploratory dry hole costs

 
35

Loss (gain) from sale of properties and equipment
(20,489
)
 
(3,928
)
Deferred income taxes
10,914

 
(14,024
)
Stock-based compensation
1,946

 
1,545

Amortization of debt discount and issuance costs
1,641

 
1,704

Other
699

 
136

Changes in assets and liabilities
(5,181
)
 
(10,623
)
Net cash provided by operating activities
44,299

 
15,476

Cash flows from investing activities:
 
 
 
Capital expenditures
(107,029
)
 
(71,079
)
Acquisition of natural gas and crude oil properties
(10,000
)
 

Proceeds from sale of properties and equipment
184,646

 
9,952

Other

 
(101
)
Net cash provided by (used in) investing activities
67,617

 
(61,228
)
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
144,750

 

Payment of credit facility
(263,000
)
 

Contribution from noncontrolling interest

 
6,407

Other
(249
)
 
(328
)
Net cash provided by (used in) financing activities
(118,499
)
 
6,079

Net decrease in cash and cash equivalents
(6,583
)
 
(39,673
)
Cash and cash equivalents, beginning of period
8,238

 
54,372

Cash and cash equivalents, end of period
$
1,655

 
$
14,699

 
 
 
 
Supplemental cash flow information:
 
 
 
Cash payments (receipts) for:
 
 
 
Interest, net of capitalized interest
$
14,975

 
$
12,314

Income taxes, net of refunds
(1,100
)
 
85

Non-cash investing activities:
 
 
 
Change in accounts payable related to purchases of properties and equipment
(21,044
)
 
5,832

Change in asset retirement obligation, with a corresponding increase to natural gas and crude oil properties, net of disposals
(1,962
)
 
229

 
 
 
 

 

See accompanying Notes to Condensed Consolidated Financial Statements
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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2012
(unaudited)


NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION

PDC Energy is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, NGLs and crude oil. As of March 31, 2012, we owned an interest in approximately 6,500 gross wells located primarily in the Appalachian Basin, the Wattenberg Field, northeast Colorado and the Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of PDC Mountaineer, LLC ("PDCM") and 21 of our affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation.
 
In our opinion, the accompanying financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of our financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2011 Form 10-K. The results of operations and the cash flows for the three months ended 2012 are not necessarily indicative of the results to be expected for the full year or any other future period.

Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. We reclassified the derivatives fair value hierarchy level of our PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2. This reclassification had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity.

NOTE 2 - RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. The adoption of these changes did not have a significant impact on our financial statements.

NOTE 3 - FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means. Includes our fixed-price swaps, basis swaps and physical purchases.

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes our natural gas and crude oil collars, crude oil puts and physical sales.

Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

We validate our fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs is valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our corporate credit facility agreement, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.
    
The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.
 
March 31, 2012
 
December 31, 2011
 
Significant other
observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
Significant other
observable
Inputs
(Level 2)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity based derivatives contracts
$
84,707

   
$
26,774

   
$
111,481

 
$
76,104

   
$
25,837

   
$
101,941

Basis protection derivative contracts
27

 
21

 
48

 
5

 
38

   
43

Total assets
84,734

 
26,795

 
111,529

 
76,109

 
25,875

 
101,984

Liabilities:
 
   
 
   
 
 
 
   
 
   
 
Commodity based derivatives contracts
18,710

 
7,151

   
25,861

 
9,888

 
3,768

   
13,656

Basis protection derivative contracts
30,467

 

   
30,467

 
35,424

 

   
35,424

Total liabilities
49,177

 
7,151

 
56,328

 
45,312

 
3,768

 
49,080

Net asset
$
35,557

 
$
19,644

 
$
55,201

 
$
30,797

 
$
22,107

 
$
52,904

 
 
 
 
 
 
 
 
 
 
 
 
    
    

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents a reconciliation of our Level 3 fair value measurements.

 
 
Three Months Ended March 31,
 
 
2012
 
2011 (1)
 
 
(in thousands)
 
 
 
 
 
Fair value, net asset, beginning of period
 
$
22,107

 
$
10,762

Changes in fair value included in statement of operations line item:
 
 
 
 
Commodity price risk management gain (loss), net
 
1,416

 
(9,885
)
Sales from natural gas marketing
 
43

 
14

Changes in fair value included in balance sheet line item (2):
 
 
 
 
Accounts receivable affiliates
 

 
49

Accounts payable affiliates
 
(52
)
 
(654
)
Settlements included in statement of operations line items:
 
 
 
 
Commodity price risk management gain (loss), net
 
(3,797
)
 
(2,910
)
Sales from natural gas marketing
 
(73
)
 
(75
)
Fair value, net asset, end of period
 
$
19,644

 
$
(2,699
)
 
 
 
 
 
Changes in unrealized gains (losses) relating to assets (liabilities) still held
 
 
 
 
as of period end, included in statement of operations line item:
 
 
 
 
Commodity price risk management gain, net
 
$
1,282

 
$
(7,538
)
Sales from natural gas marketing
 
3

 
(7
)
 
 
$
1,285

 
$
(7,545
)
 
 
 
 
 
__________
(1)
We reclassified our PEPL and CIG-based natural gas fixed-price swaps, crude oil fixed-price swaps, basis swaps and natural gas physical purchases from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of 2011 by $54.1 million). The amounts presented reflect these reclassifications and conform to current period presentation.
(2)
Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships.

The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, and is provided by a third party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts.    

See Note 4 for additional disclosure related to our derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. As of March 31, 2012, and December 31, 2011, the liability related to this plan was immaterial.
    
The portion of our long-term debt related to our corporate credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of its related interest rate. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of March 31, 2012, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $127.9 million or 111.2% of par value and the portion related to our 12% senior notes due 2018 to be $220.3 million or 108.5% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices and therefore Level 1 inputs.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

As of March 31, 2012, we had derivative instruments in place for a portion of our anticipated production through 2015 for a total of 72,997 BBtu of natural gas and 3,134 MBbls of crude oil.
    
    

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents the location and fair value amounts of our derivative instruments on the balance sheets. These derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases.
 
 
 
 
 
 
Fair Value
Derivatives instruments not designated as hedges (1):
 
Balance sheet line item
 
March 31,
2012
 
December 31,
2011
 
 
 
 
 
(in thousands)
Derivative assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
64,099

 
$
51,220

 
Related to affiliated partnerships (2)
 
Fair value of derivatives
 
8,959

 
8,018

 
Related to natural gas marketing
 
Fair value of derivatives
 
1,691

 
1,528

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
29

 
43

 
 
 
 
 
74,778

 
60,809

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
31,514

 
34,938

 
Related to affiliated partnerships (2)
 
Fair value of derivatives
 
5,207

 
6,134

 
Related to natural gas marketing
 
Fair value of derivatives
 
11

 
103

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
19

 

 
 
 
 
 
36,751

 
41,175

Total derivative assets
 
 
 
 
$
111,529

 
$
101,984

 
 
 
 
 
 
 
 
Derivative liabilities:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
10,492

 
$
7,498

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
276

 
211

 
Related to natural gas marketing
 
Fair value of derivatives
 
1,585

 
1,384

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
15,166

 
15,762

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
2,992

 
3,116

 
Related to natural gas marketing
 
Fair value of derivatives
 
2

 
3

 
 
 
 
 
30,513

 
27,974

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
13,378

 
4,357

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
123

 
113

 
Related to natural gas marketing
 
Fair value of derivatives
 
7

 
93

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
10,281

 
13,820

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
2,024

 
2,723

 
Related to natural gas marketing
 
Fair value of derivatives
 
2

 

 
 
 
 
 
25,815

 
21,106

Total derivative liabilities
 
 
 
 
$
56,328

 
$
49,080

 
 
 
 
 
 
 
 
__________
(1)
As of March 31, 2012, and December 31, 2011, none of our derivative instruments were designated as hedges.
(2)
Represents derivative positions designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets.
(3)
Represents derivative positions designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities.
    
    

11

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

The following table presents the impact of our derivative instruments on our statements of operations.

 
 
Three Months Ended March 31,
 
 
2012
 
2011
Statement of operations line item
 
Reclassification
of Realized
Gains (Losses)
Included in Prior Periods
Unrealized
 
Realized and Unrealized
Gains
(Losses) For
the
Current
Period
 
Total
 
Reclassification
of Realized
Gains (Losses)
Included in Prior Periods
Unrealized
 
Realized and Unrealized
Gains
(Losses) For
the
Current
Period
 
Total
 
 
(in thousands)
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
8,628

 
$
1,299

 
$
9,927

 
$
3,322

 
$
466

 
$
3,788

Unrealized gains (losses)
 
(8,628
)
 
10,202

 
1,574

 
(3,322
)
 
(24,348
)
 
(27,670
)
Total commodity price risk management gain (loss), net
 
$

 
$
11,501

 
$
11,501

 
$

 
$
(23,882
)
 
$
(23,882
)
Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
684

 
$
109

 
$
793

 
$
1,007

 
$
135

 
$
1,142

Unrealized gains (losses)
 
(684
)
 
759

 
75

 
(1,007
)
 
(10
)
 
(1,017
)
Total sales from natural gas marketing
 
$

 
$
868

 
$
868

 
$

 
$
125

 
$
125

Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized losses
 
$
(591
)
 
$
(154
)
 
$
(745
)
 
$
(770
)
 
$
(190
)
 
$
(960
)
Unrealized gains (losses)
 
591

 
(707
)
 
(116
)
 
770

 
172

 
942

Total cost of natural gas marketing
 
$

 
$
(861
)
 
$
(861
)
 
$

 
$
(18
)
 
$
(18
)
 
 
 
 
 
 
 
 
 
 
 
 
 

Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions, who are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is not significant.

The following table presents the counterparties that expose us to credit risk as of March 31, 2012, with regard to our derivative assets.

Counterparty Name
 
Fair Value of
Derivative Assets
As of March 31, 2012
 
 
(in thousands)
 
 
 
JPMorgan Chase Bank, N.A. (1)
 
$
55,769

Crèdit Agricole CIB (1)
 
19,441

Wells Fargo Bank, N.A. (1)
 
20,099

Other lenders in our credit facility
 
16,135

Various (2)
 
85

Total
 
$
111,529

 
 
 
__________
(1)Major lender in our credit facility, see Note 7.
(2)Represents a total of 10 counterparties.



12

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net of depreciation and assets held-for-sale.

 
March 31, 2012
 
December 31, 2011
 
(in thousands)
Properties and equipment, net:
 
 
 
Natural gas and crude oil properties
 
 
 
Proved
$
1,738,596

 
$
1,694,694

Unproved
132,499

 
102,466

Total natural gas and crude oil properties
1,871,095

 
1,797,160

Pipelines and related facilities
42,062

 
40,721

Transportation and other equipment
32,878

 
32,475

Land and buildings
13,872

 
14,572

Construction in progress
61,584

 
69,633

Gross properties and equipment
2,021,491

 
1,954,561

Accumulated DD&A
(692,031
)
 
(652,845
)
Properties and equipment, net
$
1,329,460

 
$
1,301,716

 
 
 
 

NOTE 6 - INCOME TAXES

We evaluate our estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. The estimated annual effective tax rate is adjusted quarterly based upon actual results and updated operating forecasts; consequently, based upon the mix and timing of our actual earnings compared to annual projections, our effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. A tax expense or benefit unrelated to the current year income or loss is recognized in its entirety as a discrete item of tax in the period identified. The quarterly income tax provision is generally comprised of tax on income or tax benefit on loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

The effective tax rate for continuing operations for the three months ended 2012 was a 35.5% provision on income compared to a 38.1% benefit on loss for the three months ended 2011. The effective tax rate for the three months ended 2012 differs from the statutory rate primarily due to net permanent deductions, largely percentage depletion partially offset by nondeductible officer's compensation. The effective tax rate for the three months ended 2011 differs from the statutory rate primarily due to net permanent deductions, largely percentage depletion, increasing the tax benefit on pretax loss. There were no significant discrete items recorded during each of the three months ended 2012 or 2011.

As of March 31, 2012, we had a gross liability for unrecognized tax benefits of $0.2 million, unchanged from the amount recorded at December 31, 2011. If recognized, all of this liability would affect our effective tax rate. This liability is reflected in other accrued expenses on our accompanying balance sheet. We do not expect our remaining liability for uncertain tax positions to decrease in the next twelve months.

As of the date of this filing, we are current with our income tax filings in all applicable state jurisdictions and currently have no state income tax returns in the process of examination.



13

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:
 
 
March 31, 2012
 
December 31, 2011
 
(in thousands)
Senior notes
 
 
 
3.25% Convertible senior notes due 2016:
 
 
 
Principal amount
$
115,000

 
$
115,000

Unamortized discount
(16,250
)
 
(17,079
)
3.25% Convertible senior notes due 2016, net of discount
98,750

 
97,921

12% Senior notes due 2018:


 


Principal amount
203,000

 
203,000

Unamortized discount
(1,691
)
 
(1,764
)
12% Senior notes due 2018, net of discount
201,309

 
201,236

Total senior notes
300,059

 
299,157

Credit facilities
 
 
 
Corporate
82,000

 
209,000

PDCM
32,750

 
24,000

Total credit facilities
114,750

 
233,000

Total long-term debt
$
414,809

 
$
532,157

 
 
 
 
    
Senior Notes
    
3.25% Convertible Senior Notes Due 2016. In November 2010, we issued $115 million of 3.25% convertible senior notes due 2016 in a private placement. The maturity for the payment of principal is May 15, 2016. Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15. We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, with similar terms and priced on the same day we issued our convertible notes. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using an effective interest rate of 7.4%. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares.

12% Senior Notes Due 2018. In 2008, we issued $203 million of 12% senior notes due 2018 in a private placement. The maturity for the payment of principal is February 15, 2018. Interest at the rate of 12% per year is payable in cash semiannually in arrears on each February 15 and August 15. The senior notes were issued at a discount, 98.572% of the principal amount. The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants. The original issue discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using the effective interest method.

We were in compliance with all covenants related to our senior notes as of March 31, 2012, and expect to remain in compliance throughout the next twelve-month period.

Bank Credit Facilities

Corporate Bank Credit Facility. We operate under a credit facility dated November 5, 2010, as amended last on October 12, 2011, with an aggregate revolving commitment or borrowing base of $400 million (as recently increased to $425 million). The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes, and to support letters of credit.
    
Our credit facility borrowing base is subject to size redetermination semiannually based on quantification of our reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to our and our subsidiaries’ natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 21 affiliated partnerships. The credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such

14

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

subsidiaries' other assets. Neither PDCM nor the various limited partnerships that we have sponsored and continue to serve as the managing general partner are guarantors of the credit facility. See Note 15, Subsequent Events, for a discussion on our most recent borrowing base redetermination.

Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base falls below the outstanding balance. The credit facility contains covenants customary for agreements of this type.

We have outstanding an $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market production in the Appalachian Basin. This letter of credit reduced the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of March 31, 2012) for the period the letter of credit remains outstanding. The letter of credit expires on July 20, 2012.

As of March 31, 2012, we had an outstanding balance of $82 million on our credit facility compared to $209 million as of December 31, 2011. We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our credit facility. As of March 31, 2012, the available funds under our credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $299.3 million. The weighted average borrowing rate on our credit facility, exclusive of the letter of credit, was 3.9% per annum as of March 31, 2012 compared to 3.8% as of December 31, 2011.

PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010, as amended last on November 18, 2011, with an aggregate revolving commitment or borrowing base of $80 million, of which our proportionate share would be $40 million. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at December 31 and June 30; further, either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Appalachian assets. As of March 31, 2012, our proportionate share of PDCM's outstanding credit facility draw was $32.8 million compared to $24 million as of December 31, 2011. PDCM pays a fee of 0.5% per annum on the unutilized commitment on the available funds under this credit facility.

As of March 31, 2012, both the Company and PDCM were in compliance with all bank credit facility covenants and expect to remain in compliance throughout the next twelve-month period.

NOTE 8 - ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties.

 
Amount
 
(in thousands)
 
 
Balance at December 31, 2011
$
46,566

Obligations incurred with development activities
99

Accretion expense
818

Obligations discharged with disposal of properties and asset retirements
(2,061
)
Balance at March 31, 2012
45,422

Less current portion
(250
)
Long-term portion
$
45,172

 
 

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell our natural gas and the natural gas of working interest owners, PDCM, our affiliated partnerships and other third parties. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM and affiliated partnerships. We record in our financial statements only our share of costs based upon our working interest in the wells; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC.

15

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

            
The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm sales, processing and transportation agreements for pipeline capacity.

 
 
For the Twelve Months Ending March 31,
 
 
 
 
Area
 
2013
 
2014
 
2015
 
2016
 
2017 Through
Expiration
 
Total
 
Expiration
Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Piceance Basin
 
17,951

 
36,126

 
34,656

 
29,407

 
104,851

 
222,991

 
May 31, 2021
Appalachian Basin (1)
 
15,572

 
20,117

 
22,630

 
23,856

 
183,965

 
266,140

 
September 25, 2025
NECO
 
3,195

 
1,825

 
1,825

 
1,825

 
1,370

 
10,040

 
December 31, 2016
Total
 
36,718

 
58,068

 
59,111

 
55,088

 
290,186

 
499,171

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dollar commitment
(in thousands)
 
$
16,818

 
$
28,415

 
$
28,146

 
$
25,635

 
$
121,056

 
$
220,070

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
_____________
(1)
Includes a precedent agreement that becomes effective when a planned pipeline is placed in service, currently expected to be September 2012, and represents 6,173 MMcf of the total MMcf presented for the twelve months ending March 31, 2013, 10,627 MMcf for each of the twelve months ending March 31, 2014 through 2016, respectively, and 68,277 MMcf thereafter. This agreement will be null and void if the pipeline is not completed. In August 2009, we issued a letter of credit related to this agreement, see Note 7.
    
Litigation. The Company is involved in various legal proceedings that it considers normal for its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity.

Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases

On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to 11 partnership repurchases completed by mergers in 2010 and 2011.  The action was filed in United States ("U.S.") District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp.  The complaint alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty claim.  On February 10, 2012, the Company filed a motion to dismiss or in the alternative to stay. The motion was argued on April 2, 2012. The Court has not filed a ruling at this time. The case is set for a scheduling conference on June 11, 2012.  We believe the suit is without merit and we intend to defend vigorously.

Royalty Owner Class Action

Gobel et al v. Petroleum Development Corporation, filed on January 27, 2009, in Circuit Court of Harrison County, CA No. 09-C-40-2

David W. Gobel, individually and allegedly as representative of all royalty owners in the Company's West Virginia oil and gas wells, filed a lawsuit against the Company alleging that we failed to properly pay royalties. The allegations stated that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages were requested in addition to breach of contract, tort and fraud allegations.

In April 2011, the Company entered into an oral settlement agreement with respect to this lawsuit, settling all claims between the parties for an aggregate payment of $8.7 million. On June 15, 2011, subject to court approval, a written settlement agreement was signed confirming these terms. On June 30, 2011, the state court granted initial approval of the settlement agreement, subject to notice to class members and final court approval. Initial notice was then sent to the class members. The date for objection by class members was October 24, 2011, with no objections received. Final approval and settlement occurred in January 2012 and as a result our restricted cash and accrued liability were reduced by the settlement amount.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are accrued when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of March 31, 2012 and December 31, 2011, we had accrued environmental

16

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

liabilities in the amount of $1.7 million and $2.5 million, respectively, included in other accrued expenses on the balance sheet. We are not aware of any environmental claims existing as of March 31, 2012 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties.

Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision whereby investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of March 31, 2012, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $5.3 million. We believe we have adequate liquidity to meet this obligation. For the three months ended 2012, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial.
    
Employment Agreements with Executive Officers. We have employment agreements with our executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including severance benefits.
    
If, within two years following a change in control of the Company ("change in control period"), either the Company terminates the executive officer without cause or the executive officer terminates employment for good reason, then the severance benefits owed equals three times the sum of the executive's highest annual base salary during the previous two years of employment immediately preceding the termination date and the executive's highest annual bonus paid or, in the case of one executive officer, paid or payable during the same two-year period. Mr. Trimble became President and Chief Executive Officer in June 2011 and under his employment agreement, if he is terminated without cause, he is to receive payment of salary and bonus through June 30, 2013, provided such amount will equal at least one year's salary and bonus. Where the Company terminates the executive officer without cause or the executive officer terminates employment for good reason outside of the change in control period, the severance benefits range from two times to three times, specific to the executive officer, the benefits noted above. For this purpose, a change of control and good reason correspond to the respective definitions of change of control and good reason under IRC Section 409A and the supporting Treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled under his employment agreement to (i) vesting of any unvested equity compensation (excluding all long-term incentive shares), (ii) reimbursement for any unpaid expenses, (iii) continued coverage under our medical plan at the Company's cost for the federal COBRA health continuation coverage period and (iv) payment of any earned and unpaid bonus amounts. In addition, the executive officer is entitled to receive any benefits that he would have otherwise been entitled to receive under our qualified retirement plan, although those benefits are not increased or payment accelerated.
    
In the event that an executive officer is terminated for just cause, we are required to pay the executive officer his base salary through the termination date, incentive, deferred, retirement or other compensation and to provide any other benefits, which have been earned or become payable as of the termination date.

In the event that an executive officer voluntarily terminates his employment for other than good reason, he is entitled to receive (i) his base salary and bonus, provided, however, that with respect to the bonus, for certain executive officers, there will be no proration of the bonus if such executive leaves prior to the last day of the year and, with respect to one executive officer, there will be no proration of the bonus in the event such executive officer leaves prior to March 31 in the year of his termination, (ii) any incentive, deferred or other compensation which has been earned or has become payable, but which has not yet been paid under the schedule originally contemplated in the agreement under which they were granted, (iii) any unpaid expense reimbursement and (iv) any other payments for benefits earned under the employment agreement or our plans.

In the event of death or disability, the executive officer is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC Section 409A and the supporting Treasury regulations. The benefits will (i) in the case of death of the executive officer other than the Chief Executive Officer, be paid in a lump sum and be equal to the base salary that would otherwise have been paid for a six-month period following the termination date and (ii) in the case of disability be up to thirteen weeks of ongoing base salary plus a lump sum equal to six months of base salary.



17

Table of Contents
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


NOTE 10 - COMMON STOCK

Stock-Based Compensation Plans

The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented.
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
(in thousands)
 
 
 
 
 
Total stock-based compensation expense
 
$
1,946

 
$
1,545

Income tax benefit
 
(741
)
 
(587
)
Net expense
 
$
1,205

 
$
958

 
 
 
 
 


Stock Appreciation Rights ("SARs")

The SARs will vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance.
    
In March 2012, the Compensation Committee of our Board of Directors (the "Committee") awarded 68,361 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the assumptions presented in the table below. The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.

 
Three Months Ended March 31,
 
2012
 
2011
 
 
 
 
Expected term of the award
6 years

 
6 years

Risk-free interest rate
1.1
%
 
2.5
%
Volatility
64.3
%
 
60.2
%
Weighted average grant date fair value per share
$
17.61

 
$
25.22

    
The following table presents the changes in our SARs.
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
Number
of
SARs
 
Weighted Average
Exercise
Price
 
Average Remaining Contractual
Term
(in years)
 
Aggregate Intrinsic
Value
(in thousands)
 
Number
of
SARs
 
Weighted Average
Exercise
Price
 
Average Remaining Contractual
Term
(in years)
 
Aggregate Intrinsic
Value
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding beginning of year, January 1
 
50,471

 
$
31.61

 
8.6

 
$
341

 
57,282

 
$
24.44

 
9.3

 
$
1,020

Awarded
 
68,361

 
30.19

 
9.8

 

 
31,552

 
43.95

 
10.0

 

Outstanding at March 31,
 
118,832

 
30.80

 
9.2

 
875

 
88,834

 
31.37

 
9.4

 
1,478

Vested and expected to vest at March 31,
 
111,137

 
30.76

 
9.2

 
825

 
79,951

 
31.37

 
9.4

 
1,330

Exercisable at March 31,
 
16,822

 
31.61

 
8.4

 
135

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of March 31, 2012 was $1.5 million. The cost is expected to be recognized over a weighted average period of 2.5 years.
 
    

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

Restricted Stock Awards

Time-Based Awards. In January 2012, the Committee awarded a total of 79,889 time-based restricted shares to our executive officers that vest ratably over a three-year period ending on January 16, 2015.

The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of March 31, 2012 was $12 million. This cost is expected to be recognized over a weighted average period of 2.4 years.

The following table presents the changes in non-vested time-based awards for the three months ended 2012.
 
 
Shares
 
Weighted Average
Grant-Date
Fair Value per Share
 
 
 
 
 
Non-vested at December 31, 2011
 
527,801

 
$
29.29

Granted
 
101,252

 
31.23

Vested
 
(30,543
)
 
31.74

Forfeited
 
(7,576
)
 
26.47

Non-vested at March 31, 2012
 
590,934

 
29.58

 
 
 
 
 

 
As of / Three Months Ended March 31,
 
2012
 
2011
 
(in thousands, except per share data)
 
 
 
 
Total intrinsic value of time-based awards vested
$
1,104

 
$
1,400

Total intrinsic value of time-based awards non-vested
21,918

 
25,629

Market price per common share as of March 31
37.09

 
48.01

Weighted average grant date fair value per share
31.23

 
43.95


Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.
    
In March 2012, the Committee awarded a total of 30,541 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2014, and can result in a payout between zero and 200% of the total shares awarded. The weighted average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the weighted average assumptions presented in the table below.

 
 
Three Months Ended March 31,
 
 
2012
 
2011
 
 
 
 
 
Expected term of award
 
3 years

 
3 years

Risk-free interest rate
 
0.3
%
 
1.1
%
Volatility
 
65.3
%
 
74.2
%
Weighted average grant date fair value per share
 
$
36.54

 
$
58.53


Expected volatility was based on our historical volatility. The expected lives of the awards were based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award. We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


The following table presents the change in non-vested market-based awards for the three months ended 2012.

 
Shares
 
Weighted Average
Grant-Date
Fair Value per Share
 
 
 
 
Non-vested at December 31, 2011
43,081

 
$
42.05

Granted
30,541

 
36.54

Non-vested at March 31, 2012
73,622

 
41.87

 
 
 
 

The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of March 31, 2012, was $1.2 million. This cost is expected to be recognized over a weighted average period of 2.5 years.

Treasury Share Purchases

In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to cover tax withholding obligations upon the vesting and exercise of share-based awards. The shares acquired may be retired or reissued to service awards under our 2010 Long-Term Equity Compensation Plan (the "2010 Plan"). For shares that are retired, we first charge any excess of cost over the par value to additional paid-in-capital ("APIC") to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance, we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted average cost per share with an offsetting charge to APIC. During the three months ended March 31, 2012, we acquired 10,035 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 6,162 shares were retired and the remaining 3,873 shares are available for reissuance pursuant to our 2010 Plan.


NOTE 11 - EARNINGS PER SHARE

The following is a reconciliation of weighted average diluted shares outstanding.

 
Three Months Ended March 31,
 
2012
 
2011
 
(in thousands)
 
 
 
 
Weighted average common shares outstanding - basic
23,609

 
23,428

Dilutive effect of share-based compensation:
 
 
 
Restricted stock
212

 

SARs
65

 

Non employee director deferred compensation
3

 

Weighted average common and common share equivalents outstanding - diluted
23,889

 
23,428

 
 
 
 

The following table sets forth the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect.
 
Three Months Ended March 31,
 
2012
 
2011
 
(in thousands)
Weighted average common share equivalents excluded from diluted earnings
 
 
 
per share due to their anti-dilutive effect:
 
 
 
Restricted stock
27

 
603

Stock options
7

 
10

SARs
19

 
64

Convertible debt

 
161

Non employee director deferred compensation

 
3

Total anti-dilutive common share equivalents
53

 
841

 
 
 
 

20

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued


In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount, that give the holders the right to convert the principal amount into 2.7 million common shares at a conversion price of $42.40 per share. The convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the conversion price. The average price did not exceed $42.40 per share during the three months ended 2012 or 2011.

NOTE 12 - DIVESTITURES AND DISCONTINUED OPERATIONS

Permian Basin. In October 2011, we developed a plan to divest our Permian Basin assets. The plan included 100% of our Permian Basin assets, consisting of producing wells and undeveloped leaseholds. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement which was approved by our Board of Directors (the "Board"), with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third party, for the sale of our core Permian Basin assets for a sale price of $173.9 million, subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011, and the results of operations related to those assets have been separately reported as discontinued operations in the condensed consolidated statement of operations for all periods presented. On February 28, 2012, the divestiture closed with total proceeds received of $184.4 million after preliminary closing adjustments, resulting in a pretax gain on sale of $20.3 million.

North Dakota. During the fourth quarter of 2010, we developed a plan to divest our North Dakota assets. The plan included 100% of our North Dakota assets, consisting of producing wells, undeveloped leaseholds and related facilities primarily located in Burke County. The plan received approval from our Board and, in December 2010, we effected a letter of intent with an unrelated third party. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pretax gain on sale of $3.9 million. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets; accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in the condensed consolidated statement of operations for the three months ended 2011.
    
Selected financial information related to divested and discontinued operations. The table below presents selected operational information related to discontinued operations. While the reclassification of revenues and expenses related to discontinued operations for the prior period had no impact upon previously reported net earnings, the statement of operations table below presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations. The three months ended 2011, in addition to the discontinued operations data of our Permian assets, includes operations data related to the February 2011 divestiture of our North Dakota assets.

 
 
Three Months Ended March 31,
Statement of Operations - Discontinued Operations
 
2012
 
2011
 
 
(dollars in thousands)
Revenues
 
 
 
 
Natural gas, NGL and crude oil sales
 
$
4,456

 
$
5,516

Well operations, pipeline income and other
 
34

 
43

Total revenues
 
4,490

 
5,559

 
 
 
 
 
Costs, expenses and other
 
 
 
 
Production costs
 
1,668

 
2,699

Exploration expense
 

 
29

Depreciation, depletion and amortization
 

 
1,372

Gain on sale of properties and equipment
 
(20,335
)
 
(3,854
)
Total costs, expenses and other
 
(18,667
)
 
246

 
 
 
 
 
Income from discontinued operations
 
23,157

 
5,313

Provision for income taxes
 
8,702

 
1,990

Income from discontinued operations, net of tax
 
$
14,455

 
$
3,323


NOTE 13 - TRANSACTIONS WITH AFFILIATES AND OTHER RELATED PARTIES
    
Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by our affiliated partnerships in the Eastern Operating Region. Our sales from natural gas marketing include $0.1 million and $0.2 million for the three months ended 2012 and 2011,

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

respectively, related to the marketing of natural gas on behalf of our affiliated partnerships. Our cost of natural gas marketing includes $0.1 million and $0.2 million for the three months ended 2012 and 2011, respectively, related to these sales.

Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We have entered into derivative instruments on behalf of our 21 affiliated partnerships for their estimated production. As of March 31, 2012 and December 31, 2011, we had a payable to affiliates of $14.2 million, representing their designated portion of the fair value of our gross derivative assets; and a receivable from affiliates of $5.4 million and $6.2 million, respectively, representing their designated portion of the fair value of our gross derivative liabilities.

We provide well operations and pipeline services to our affiliated partnerships. The majority of our revenue and expenses related to well operations and pipeline income are associated with services provided to our affiliated partnerships.
    
PDCM. Our Gas Marketing segment markets the natural gas produced by PDCM. Our sales from natural gas marketing include $2.4 million and $1.8 million for the three months ended 2012 and 2011, respectively, related to the marketing of natural gas on behalf of PDCM. Our cost of natural gas marketing includes $2.4 million and $1.8 million for the three months ended 2012 and 2011, respectively, related to these sales.
 
We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $3.2 million and $2.7 million in the three months ended 2012 and 2011, respectively. Our statements of operations include only our proportionate share of these billings.

NOTE 14 - BUSINESS SEGMENTS

We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated.

Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGL and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and DD&A expense.

Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) represents sales from natural gas marketing less costs of natural gas marketing.

Unallocated amounts. Unallocated income includes unallocated other revenue less corporate general administrative expense, corporate DD&A expense, interest income and interest expense.
    
The following tables present our segment information.

 
Three Months Ended March 31,
 
2012
 
2011
 
(in thousands)
Revenues:
 
 
 
Oil and Gas Exploration and Production
$
88,512

 
$
36,771

Gas Marketing
11,834

 
15,202

Total
$
100,346

 
$
51,973

 
 
 
 
Segment income (loss) before income taxes:
 
 
 
Oil and Gas Exploration and Production
$
28,627

 
$
(14,044
)
Gas Marketing
342

 
209

Unallocated
(26,830
)
 
(23,690
)
Total
$
2,139

 
$
(37,525
)
 
 
 
 


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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued

 
March 31, 2012
 
December 31, 2011
 
(in thousands)
Segment assets:
 
 
 
Oil and Gas Exploration and Production
$
1,509,577

 
$
1,461,130

Gas Marketing
7,171

 
14,713

Unallocated
48,821

 
73,913

Assets held for sale

 
148,249

Total
$
1,565,569

 
$
1,698,005

 
 
 
 

NOTE 15 - SUBSEQUENT EVENTS

On May 4, 2012, the semiannual redetermination of our corporate bank credit facility's borrowing base, which was based upon our natural gas and crude oil reserves as of December 31, 2011, was completed. Based on the redetermination, our aggregate revolving commitment was increased to $425 million from $400 million. There were no other changes to our corporate bank credit facility as a result of the redetermination.




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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Financial Overview

During the three months ended 2012, we recorded strong increases in Natural gas, NGL and crude oil sales as a direct result of our significant increase in production. Total Natural gas, NGL and crude oil sales increased $16.5 million, or 28.1%, to $75.3 million from $58.8 million for the same period in 2011. Driven by the success of our horizontal Niobrara program, crude oil and NGL production from continuing operations increased 72.9% and 53.8%, respectively, compared to the same period in 2011. These significant increases in production of liquids improved our liquids percentage of total production to 36% from 27% for the comparable three month period in 2011. Our significant increase in liquids more than offset the reduction in natural gas prices. In addition to the net increase in Natural gas, NGL and crude oil sales, our realized gains from derivative transactions increased 151.3% to $10 million during the period compared to $4 million in 2011.

While significantly increasing our total revenues, we were able to control our costs and had only modest increases in production costs, exploration expense and general and administrative costs. On a per unit basis, production cost decreased from $1.76 per Mcfe to $1.47 per Mcfe, general and administrative costs decreased from $1.32 per Mcfe to $1.12 per Mcfe, while exploration expense remained consistent at $0.16 per Mcfe.
    
Available liquidity as of March 31, 2012 was $308.1 million, which included $7.2 million through our joint venture PDCM, compared to $196.4 million, which included $16.6 million related to PDCM, as of December 31, 2011. Available liquidity is comprised of cash, cash equivalents and funds available under our credit facility. The increased liquidity amount as of March 31, 2012 was primarily attributable to proceeds received from the disposition of our Permian assets in February 2012 and the increased cash flow from operations during the period. Our strong liquidity position has afforded us the opportunity to execute and implement our increased 2012 drilling program and continue to pursue potential acquisitions of oil and natural gas properties in our liquids rich basins.

With our shift to liquids and strong derivatives program, and despite the divestiture of our Permian assets, on May 4, 2012, we completed the redetermination of our corporate bank credit facility's borrowing base, resulting in an increase in our March 31, 2012 available liquidity of $25 million from $400 million to $425 million. See Note 15, Subsequent Events, to the accompanying condensed consolidated financial statements.

Operational Overview

Drilling Activities. During the three months ended 2012, we continued to focus our operations and leasehold acquisitions primarily in the liquids-rich Wattenberg Field of Colorado and the emerging Utica Shale play in Ohio. We drilled six horizontal wells in the Wattenberg Field during the quarter, of which three were completed and turned in line as of March 31, 2012, and participated in three vertical non-operated drilling projects. We also executed 59 refrac/recompletion projects on 31 wells in the Wattenberg area. The shift in the Wattenberg Field from drilling a combination of both vertical and horizontal wells to our current program of drilling primarily horizontal wells has resulted in significantly fewer wells being drilled at a considerably higher expenditure per well and related production and reserves per well. The remaining activity in our Western Operating Region was the completion of our final three Piceance wells from our 2011 capital plan.

PDCM drilled three horizontal Marcellus wells during the quarter, all of which were in-process as of March 31, 2012, before laying down the rig due to the deterioration of natural gas prices in the Appalachian Basin. In addition to PDCM's drilling activity, we completed our first Utica well in our Eastern Operating Region.

Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our assets located in the Wolfberry Trend in the Permian Basin in West Texas to focus our efforts on our horizontal drilling programs. During the fourth quarter of 2011, we sold our non-core Permian assets to unrelated third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with another unrelated third party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, the divestiture closed with total proceeds received of $184.4 million after preliminary closing adjustments, resulting in a pretax gain on sale of $20.3 million. The proceeds from these sales were used to pay down our corporate credit facility and to provide partial funding for our 2012 capital budget, allowing us to accelerate the development of our liquid-rich inventory of projects in the Wattenberg Field and to fund the acquisition of Utica Shale acreage in Ohio, while beginning exploratory activities on this acreage. The results of operations related to our Permian Basin assets are reported as discontinued operations, for all periods presented in the accompanying consolidated statements of operations included in this report.

Current Low Natural Gas Price Environment. The natural gas market continues to be characterized by depressed prices. While we have derivative instruments in place for a majority of our expected natural gas production in 2012 and 2013, sustained low natural gas prices would result in higher realized derivative gains upon settlement but also could have a material adverse effect as a result of lower natural gas sales, a reduction in the estimated quantity of proved reserves and the estimated future net cash flows expected to be generated from these reserves. The above factors could result in a reduction of our credit facility and possible future asset impairments. See Item 3, Quantitative and Qualitative Disclosures About Market Risk.

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

.

Non-U.S. GAAP Financial Measures

We use "adjusted cash flow from operations," "adjusted net income (loss) attributable to shareholders" and "adjusted EBITDA," non-U.S. GAAP financial measures, for internal managerial purposes, when evaluating period-to-period changes and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income, cash flows from operations, investing or financing activities, and should not be viewed as a liquidity measure or indicator of operating results or cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures as well as a reconciliation of each to the nearest U.S. GAAP measure.

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

Results of Operations

Summary Operating Results

The following table presents selected information regarding our operating results from continuing operations.
 
Three Months Ended March 31,
 
2012
 
2011
 
Change
 
(dollars in millions, except per unit data)
Production (1)
 
 
 
 
 
Natural gas (MMcf)
8,374.1

 
7,666.2

 
9.2
 %
Crude oil (MBbls)
555.2

 
321.2

 
72.9
 %
NGLs (MBbls)
228.8

 
148.8

 
53.8
 %
Natural gas equivalent (MMcfe) (2)
13,077.8

 
10,485.9

 
24.7
 %
Average MMcfe per day
143.7

 
116.5

 
23.3
 %
Natural Gas, NGL and Crude Oil Sales
 
 
 
 
 
Natural gas
$
17.5

 
$
23.4

 
(25.2
)%
Crude oil
51.4

 
28.8

 
78.5
 %
NGLs
6.4

 
6.6

 
(2.5
)%
Total natural gas, NGL and crude oil sales
$
75.3

 
$
58.8

 
28.1
 %
 
 
 
 
 
 
Realized Gain (Loss) on Derivatives, net (3)
 
 
 
 
 
Natural gas
$
12.5

 
$
6.9

 
81.2
 %
Crude oil
(2.6
)
 
(3.1
)
 
(16.1
)%
Total realized gain on derivatives, net
$
9.9

 
$
3.8

 
160.8
 %
 
 
 
 
 
 
Average Sales Price (excluding gain/loss on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
2.09

 
$
3.06

 
(31.7
)%
Crude oil (per Bbl)
92.61

 
89.62

 
3.3
 %
NGLs (per Bbl)
28.12

 
44.32

 
(36.6
)%
Natural gas equivalent (per Mcfe)
5.76

 
5.61

 
2.7
 %
 
 
 
 
 
 
Average Sales Price (including gain/loss on derivatives)
 
 
 
 
 
Natural gas (per Mcf)
$
3.58

 
$
3.95

 
(9.4
)%
Crude oil (per Bbl)
87.94

 
79.98

 
10.0
 %
NGLs (per Bbl)
28.12

 
44.32

 
(36.6
)%
Natural gas equivalent (per Mcfe)
6.52

 
5.97

 
9.2
 %
 
 
 
 
 
 
Average Lifting Cost (per Mcfe) (4)
$
0.88

 
$
1.06

 
(16.9
)%
 
 
 
 
 
 
Natural Gas Marketing (5)
$
0.3

 
$
0.2

 
50.0
 %
 
 
 
 
 
 
Other Costs and Expenses
 
 
 
 
 
Exploration expense
$
2.1

 
$
1.7

 
23.6
 %
General and administrative expense
14.7

 
13.9

 
6.0
 %
Depreciation, depletion and amortization
39.8

 
31.0

 
28.5
 %
 
 
 
 
 
 
Interest Expense
$
10.4

 
$
9.1

 
15.3
 %
Amounts may not recalculate due to rounding.
______________
(1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage interest we own.
(2)
Six Mcf of natural gas equals one Bbl of crude oil or NGL.
(3)
Represents realized derivative gains and losses related to natural gas and crude oil sales segment, which does not include realized derivative gains and losses related to natural gas marketing.
(4)
Represents lease operating expenses, exclusive of production taxes, on a per unit basis.
(5)
Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to

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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

natural gas marketing activities.

Natural Gas, NGL and Crude Oil Sales

The following tables present natural gas, NGL and crude oil production and average sales price by operating region.

 
Three Months Ended March 31,
 
2012
 
2011
 
Percentage
Change
Production
 
 
 
 
 
Natural gas (MMcf)
 
 
 
 
 
Western
6,880.2

 
6,787.5

 
1.4
 %
Eastern
1,485.5

 
866.9

 
71.4
 %
Other
8.4

 
11.8

 
(28.8
)%
Total
8,374.1

 
7,666.2

 
9.2
 %
Crude oil (MBbls)
 
 
 
 
 
Western
552.8

 
320.0

 
72.8
 %
Eastern
2.4

 
1.1

 
118.2
 %
Other

 
0.1

 
(100.0
)%
Total
555.2

 
321.2

 
72.9
 %
NGLs (MBbls)
 
 
 
 
 
Western
227.2

 
147.5

 
54.0
 %
Other
1.6

 
1.3

 
23.1
 %
Total
228.8

 
148.8

 
53.8
 %
Natural gas equivalent (MMcfe)
 
 
 
 
 
Western
11,559.0

 
9,592.0

 
20.5
 %
Eastern
1,499.8

 
873.7

 
71.7
 %
Other
19.0

 
20.2

 
(5.9
)%
Total
13,077.8

 
10,485.9

 
24.7
 %
 
 
 
 
 
 

Amounts may not recalculate due to rounding.




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PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

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