petro.dev-10Q-2Q11


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 June 30, 2011

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 Web site, 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: 23,590,922 shares of the Company's Common Stock ($0.01 par value) were outstanding as of July 22, 2011.






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.
 
 
 
 
 
 
 




SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This periodic 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 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 ("NGL") and crude oil production and reserves; drilling plans; future cash flows and anticipated liquidity; anticipated capital expenditures, including our ability to fund our 2011 capital plan; our expected production growth from continuing operations in 2011 and our increased 2011 capital expenditure budget; our plan to release our drilling rig in the Piceance Basin in 2011 and resume drilling in mid-2012; our compliance with our debt covenants and the indenture restrictions governing our senior notes; sufficient liquidity to meet our partnership repurchase obligations; that the acquisition of partnerships will provide us with growth in production and proved reserves; the adequacy of our casualty insurance coverage as managing general partner of numerous partnerships; the impact of decreased commodity prices on future borrowing base redeterminations; the effectiveness of our derivative policies in achieving our risk management objectives; funding sources for our acquisitions; the acceleration of our capital spending program due to a rise in crude oil prices; our ability to benefit from crude oil and natural gas price differential; our ability to successfully acquire the 2003/2002-D Partnerships; and our management’s 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;
volatility of commodity prices for natural gas and crude oil;
changes in estimates of proved reserves;
inaccuracy of reserve estimates and expected production rates;
declines in the values of our natural gas and crude oil properties resulting in impairments;
the future cash flow, liquidity and financial position of the Company;
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;
reductions in the borrowing base under our credit facility;
risks incidental to the drilling and operation of natural gas and crude oil wells;
the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
changes in environmental laws, the regulation and enforcement of those laws and the costs to comply with those laws;
the impact of environmental events, governmental responses to the events and our ability to insure adequately against such events;
the timing and receipt of necessary regulatory permits;
competition in the oil and gas industry;
the success of the Company in marketing oil and gas;
the effect of natural gas and crude oil derivatives activities;
the availability and cost of capital to us;
the cost of pending or future litigation;
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, 2010, filed with the United States Securities and Exchange Commission ("SEC") on February 24, 2011, as amended April 21, 2011, and May 18, 2011 ("2010 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



REFERENCES

Unless the context otherwise requires, references to "PDC," "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation, and its consolidated entities. 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 entities.

References to "the three months ended 2011" and "the six months ended 2011" refer to the three and six months ended June 30, 2011, respectively. References to "the three months ended 2010" and "the six months ended 2010" refer to the three and six months ended June 30, 2010, respectively.

References to "quarter-over-quarter" refer to the three months ended 2011 compared to the three months ended 2010. References to "year-over-year" refer to the six months ended 2011 compared to the six months ended 2010.



4



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)
 
June 30, 2011
 
December 31, 2010 (1)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
6,771

 
$
54,372

Accounts receivable, net
57,221

 
53,978

Accounts receivable affiliates
9,257

 
11,448

Fair value of derivatives
38,797

 
42,953

Prepaid expenses and other current assets
15,855

 
14,072

Total current assets
127,901

 
176,823

Properties and equipment, net
1,244,413

 
1,120,038

Assets held for sale

 
5,191

Fair value of derivatives
34,546

 
44,464

Accounts receivable affiliates
4,819

 
8,478

Other assets
32,006

 
34,041

Total Assets
$
1,443,685

 
$
1,389,035

 
 
 
 
Liabilities and Equity
 
 
 
Liabilities
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
103,620

 
$
47,271

Accounts payable affiliates
8,084

 
9,605

Production tax liability
18,490

 
16,226

Fair value of derivatives
30,349

 
29,998

Funds held for distribution
30,755

 
29,755

Accrued interest payable
10,396

 
10,051

Other accrued expenses
21,408

 
17,723

Total current liabilities
223,102

 
160,629

Long-term debt
314,124

 
295,695

Deferred income taxes
179,711

 
187,999

Asset retirement obligations
28,414

 
27,797

Fair value of derivatives
32,230

 
36,644

Accounts payable affiliates
7,353

 
12,111

Other liabilities
21,360

 
25,919

Total liabilities
806,294

 
746,794

 
 
 
 
Commitments and contingent liabilities

 

 
 
 
 
Equity
 
 
 
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: 23,565,040 in 2011 and 23,462,326 in 2010
236

 
235

Additional paid-in capital
215,237

 
209,198

Retained earnings
422,084

 
432,843

Treasury shares, at cost: 6,238 in 2011 and 2,938 in 2010
(242
)
 
(111
)
Total shareholders' equity
637,315

 
642,165

Noncontrolling interest in subsidiary
76

 
76

Total equity
637,391

 
642,241

Total Liabilities and Equity
$
1,443,685

 
$
1,389,035

 
 
 
 
__________
(1)    Derived from audited 2010 balance sheet.

See accompanying Notes to Condensed Consolidated Financial Statements
5



PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2011
 
2010
 
2011
 
2010
Revenues:
 
 
 
 
 
 
 
Natural gas, NGL and crude oil sales
$
72,215

 
$
48,729

 
$
136,094

 
$
106,556

Sales from natural gas marketing
18,897

 
12,589

 
34,099

 
35,276

Commodity price risk management gain (loss), net
20,537

 
12,257

 
(3,345
)
 
55,479

Well operations, pipeline income and other
1,781

 
2,148

 
3,657

 
4,737

Total revenues
113,430

 
75,723

 
170,505

 
202,048

 
 
 
 
 
 
 
 
Costs, expenses and other:
 
 
 
 
 
 
 
Production costs
19,674

 
16,004

 
40,713

 
30,965

Cost of natural gas marketing
18,207

 
12,207

 
33,200

 
34,530

Exploration expense
1,720

 
3,830

 
3,871

 
10,248

General and administrative expense
19,509

 
9,855

 
33,382

 
20,549

Depreciation, depletion and amortization
32,674

 
26,945

 
65,031

 
54,403

Gain on sale of properties and equipment

 
(96
)
 

 
(96
)
Total costs, expenses and other
91,784

 
68,745

 
176,197

 
150,599

 
 
 
 
 
 
 
 
Income (loss) from operations
21,646

 
6,978

 
(5,692
)
 
51,449

Interest income
2

 
34

 
11

 
39

Interest expense
(9,067
)
 
(7,672
)
 
(18,129
)
 
(15,472
)
 
 
 
 
 
 
 
 
Income (loss) from continuing operations before income taxes
12,581

 
(660
)
 
(23,810
)
 
36,016

Provision (benefit) for income taxes
3,416

 
(238
)
 
(10,431
)
 
13,566

Income (loss) from continuing operations
9,165

 
(422
)
 
(13,379
)
 
22,450

Income (loss) from discontinued operations, net of tax

 
(2,313
)
 
2,620

 
(1,516
)
Net income (loss)
9,165

 
(2,735
)
 
(10,759
)
 
20,934

Less: net loss attributable to noncontrolling interests

 
(6
)
 

 
(61
)
Net income (loss) attributable to shareholders
$
9,165

 
$
(2,729
)
 
$
(10,759
)
 
$
20,995

 
 
 
 
 
 
 
 
Amounts attributable to Petroleum Development Corporation shareholders:
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
9,165

 
$
(416
)
 
$
(13,379
)
 
$
22,511

Income (loss) from discontinued operations, net of tax

 
(2,313
)
 
2,620

 
(1,516
)
Net income (loss) attributable to shareholders
$
9,165

 
$
(2,729
)
 
$
(10,759
)
 
$
20,995

 
 
 
 
 
 
 
 
Earnings (loss) per share attributable to shareholders:
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.39

 
$
(0.03
)
 
$
(0.57
)
 
$
1.17

Income (loss) from discontinued operations

 
(0.12
)
 
0.11

 
(0.08
)
Net income (loss) attributable to shareholders
$
0.39

 
$
(0.15
)
 
$
(0.46
)
 
$
1.09

Diluted
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.39

 
$
(0.03
)
 
$
(0.57
)
 
$
1.17

Income (loss) from discontinued operations

 
(0.12
)
 
0.11

 
(0.08
)
Net income (loss) attributable to shareholders
$
0.39

 
$
(0.15
)
 
$
(0.46
)
 
$
1.09

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
23,491

 
19,213

 
23,460

 
19,202

Diluted
23,723

 
19,213

 
23,460

 
19,296

 
 
 
 
 
 
 
 
 

See accompanying Notes to Condensed Consolidated Financial Statements
6



PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)

 
Six Months Ended June 30,
 
2011
 
2010
Cash flows from operating activities:
 
 
 
Net income (loss)
$
(10,759
)
 
$
20,934

Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
 
 
 
Unrealized (gain) loss on derivatives, net
9,094

 
(24,701
)
Depreciation, depletion and amortization
65,031

 
55,867

Amortization and impairment of natural gas and crude oil properties
952

 
5,662

Exploratory dry hole costs
171

 
3,552

Loss (gain) from sale of properties and equipment
(3,928
)
 
169

Deferred income taxes
(10,543
)
 
11,885

Other
10,175

 
4,811

Changes in assets and liabilities
11,401

 
17,192

Net cash provided by operating activities
71,594

 
95,371

Cash flows from investing activities:
 
 
 
Capital expenditures
(151,355
)
 
(77,861
)
Deconsolidation/change in ownership effect on cash and cash equivalents
(101
)
 
(3,472
)
Proceeds from sale of properties and equipment
10,062

 
746

Other
1,643

 

Net cash used in investing activities
(139,751
)
 
(80,587
)
Cash flows from financing activities:
 
 
 
Proceeds from credit facility
65,927

 
130,000

Payment of credit facility
(49,526
)
 
(173,000
)
Contribution by investing partner in PDCM
6,407

 
16,173

Other
(2,252
)
 
(454
)
Net cash provided by (used in) financing activities
20,556

 
(27,281
)
Net decrease in cash and cash equivalents
(47,601
)
 
(12,497
)
Cash and cash equivalents, beginning of period
54,372

 
31,944

Cash and cash equivalents, end of period
$
6,771

 
$
19,447

 
 
 
 
Supplemental cash flow information:
 
 
 
Cash payments (receipts) for:
 
 
 
Interest, net of capitalized interest
$
14,328

 
$
15,607

Income taxes, net of refunds
148

 
(27,042
)
Non-cash investing activities:
 
 
 
Change in accounts payable related to purchases of properties and equipment, including 2005 Partnership acquisition
48,572

 
10,944

Change in asset retirement obligation, with a corresponding increase to properties and equipment, net of disposals
304

 
723

 
 
 
 

 

See accompanying Notes to Condensed Consolidated Financial Statements
7

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2011
(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 June 30, 2011, we owned an interest in approximately 5,000 wells located primarily in the Rocky Mountain Region and the Permian and Appalachian Basins. We operate through two business segments: (1) natural gas and crude oil sales and (2) natural gas marketing.

The accompanying unaudited condensed consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, an entity in which we have a controlling financial interest and our proportionate share of PDC Mountaineer, LLC ("PDCM"), a joint venture between PDC Energy and Lime Rock Partners, and 26 affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying 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. As of June 30, 2011, PDCM was consolidated at 52.7% and the 26 partnerships were consolidated at varying percentages.

As of December 31, 2010, PDCM was consolidated at 55.8%, representing our ownership interest. On January 1 and March 1, 2011, our joint venture partner made capital contributions of cash to PDCM of $7 million and $5 million, respectively. The contributions resulted in our ownership interest decreasing from 55.8% to 53.9%, then to 52.7%. Each change in our ownership interest resulted in a decrease in our proportionate share of net assets and any future earnings.

With the exception of our initial capital contribution in October 2009, we have not entered into any arrangement that would require us to provide financial support to PDCM. Further, we are not liable for any debts, obligations or liabilities of the joint venture and its creditors have no recourse against our general credit in the event of default. None of our affiliated partnerships’ wells were included in the joint venture.

The following table presents the carrying amount and classification of our proportionate share of PDCM's assets and liabilities included in our balance sheets.

 
June 30, 2011
 
December 31, 2010
 
(in thousands)
 
 
 
 
Cash and cash equivalents
$
578

 
$
1,560

Other current assets
4,230

 
3,206

Total current assets
4,808

 
4,766

Properties and equipment, net
109,324

 
101,679

Other assets
2,104

 
1,986

Total assets
116,236

 
108,431

Total current liabilities
4,659

 
4,641

Long-term debt
7,900

 

Asset retirement obligations
8,408

 
8,681

Other liabilities
1,651

 
1,370

Total liabilities
22,618

 
14,692

 
 
 
 

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 2010 Form 10-K. The results of operations for the three and six months ended 2011, and the cash flows for the same periods, 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, specifically related to our discontinued operations. The reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. See Note 12 for additional information regarding our discontinued operations. Additionally, certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the

8

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

fair value level classification of certain derivative instruments. The reclassification had no impact on previously reported financial position, cash flows, net income, earnings per share or shareholders' equity. See Note 3 for additional information regarding the fair value classification of our natural gas and crude oil derivative instruments.

NOTE 2 - RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for our financial statements issued for the annual reporting period, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on our financial statements.

Recently Issued 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 also 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. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on our financial statements.

Presentation of Comprehensive Income. On June 16, 2011, the FASB issued changes related to the presentation of comprehensive income. These changes eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. These changes are intended to enhance comparability between entities that report under U.S. GAAP and those that report under IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity's equity. An entity may elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements. Each component of net income and each component of other comprehensive income, together with totals for comprehensive income and its two parts, net income and other comprehensive income, would need to be displayed under either alternative. The statement(s) would need to be presented with equal prominence as the other primary financial statements. The new requirement is effective for public entities as of the beginning of a fiscal year that begins after December 15, 2011, and interim and annual periods thereafter. Early adoption is permitted, but full retrospective application is required under both sets of accounting standards. We do not expect the adoption of these changes to have a material impact on our financial statements.
 
NOTE 3 - FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. 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. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 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.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

    

9

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

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. The counterparties to our derivative instruments are primarily financial institutions who are also major lenders in our credit facility agreement. 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 are 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.

The following table presents, for each hierarchy level, our derivative assets and liabilities, both current and non-current portions, including the derivative assets and liabilities designated to our affiliated partnerships and our proportionate share of PDCM's derivative assets and liabilities, measured at fair value on a recurring basis.

 
June 30, 2011
 
December 31, 2010 (a)
 
Level 2 (b)
  
Level 3 (c)
  
Total
 
Level 2 (b)
  
Level 3 (c)
  
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
 
 
 
 
 
Commodity based derivatives contracts
$
61,089

   
$
12,198

   
$
73,287

 
$
72,880

   
$
14,426

   
$
87,306

Basis protection derivative contracts

 
56

 
56

 
10

 
101

   
111

Total assets
61,089

 
12,254

 
73,343

 
72,890

 
14,527

 
87,417

Liabilities:
 
   
 
   
 
 
 
   
 
   
 
Commodity based derivatives contracts
14,076

 
6,464

   
20,540

 
16,304

 
3,758

   
20,062

Basis protection derivative contracts
42,039

 

   
42,039

 
46,573

 
7

   
46,580

Total liabilities
56,115

 
6,464

 
62,579

 
62,877

 
3,765

 
66,642

Net asset
$
4,974

 
$
5,790

 
$
10,764

 
$
10,013

 
$
10,762

 
$
20,775

 
 
 
 
 
 
 
 
 
 
 
 
__________
(a)
We reclassified our NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $64.1 million, with a corresponding increase in Level 2), 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 in Level 3 by $54.1 million, with a corresponding increase in Level 2). The amounts presented reflect these reclassifications and conform to current period presentation.
(b)
Includes our fixed-price swaps, basis swaps and physical purchases.
(c)
Includes our natural gas and crude oil collars, crude oil puts and physical sales.

    

10

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.

 
 
Six Months Ended June 30,
 
 
2011
 
2010 (1)
 
 
(in thousands)
 
 
 
 
 
Fair value, net asset, beginning of period
 
$
10,762

 
$
15,048

Changes in fair value included in statement of operations line item:
 
 
 
 
Commodity price risk management gain (loss), net
 
(2,108
)
 
12,912

Sales from natural gas marketing
 
20

 
352

Cost of natural gas marketing
 

 
23

Changes in fair value included in balance sheet line item (2):
 
 
 
 
Accounts receivable affiliates
 
49

 
10

Accounts payable affiliates
 
(637
)
 
(1,468
)
Settlements included in statement of operations line items:
 
 
 
 
Commodity price risk management gain (loss), net
 
(2,210
)
 
(11,144
)
Sales from natural gas marketing
 
(86
)
 
(183
)
Cost of natural gas marketing
 

 
(23
)
Fair value, net asset, end of period
 
$
5,790

 
$
15,527

 
 
 
 
 
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 (loss), net
 
$
(1,809
)
 
12,560

Sales from natural gas marketing
 
(5
)
 
176

 
 
$
(1,814
)
 
$
12,736

 
 
 
 
 
__________
(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 the period by $44.0 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.

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 June 30, 2011, and December 31, 2010, the liability related to this plan was $0.1 million, which was included in other liabilities on the balance sheet.
    
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 June 30, 2011, we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2015 to be $111.7 million or 97.1% of par value and the portion related to our 12% senior notes due 2018 to be $226.3 million or 111.5% of par value. We determined these valuations based upon measurements of broker/dealer quotes and trading activity, respectively.

NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS

As of June 30, 2011, we had derivative instruments in place for a portion of our anticipated production through 2015 for a total of 40,785.5 BBtu of natural gas and 2,358.5 MBbls of crude oil.
    
    

11

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
 
June 30,
2011
 
December 31,
2010
 
 
 
 
 
(in thousands)
Derivative assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
31,102

 
$
32,837

 
Related to affiliated partnerships (2)
 
Fair value of derivatives
 
6,665

 
8,231

 
Related to natural gas marketing
 
Fair value of derivatives
 
980

 
1,811

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
50

 
74

 
 
 
 
 
38,797

 
42,953

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
27,180

 
32,270

 
Related to affiliated partnerships (2)
 
Fair value of derivatives
 
7,353

 
12,111

 
Related to natural gas marketing
 
Fair value of derivatives
 
7

 
46

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
6

 
37

 
 
 
 
 
34,546

 
44,464

Total derivative assets
 
 
 
 
$
73,343

 
$
87,417

 
 
 
 
 
 
 
 
Derivative liabilities:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
$
9,881

 
$
10,636

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
760

 
1,676

 
Related to natural gas marketing
 
Fair value of derivatives
 
767

 
1,492

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
14,983

 
11,725

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
3,947

 
4,462

 
Related to natural gas marketing
 
Fair value of derivatives
 
11

 
7

 
 
 
 
 
30,349

 
29,998

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
9,171

 
6,231

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
(25
)
 
(3
)
 
Related to natural gas marketing
 
Fair value of derivatives
 
(14
)
 
30

 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and crude oil sales
 
Fair value of derivatives
 
18,255

 
21,905

 
Related to affiliated partnerships (3)
 
Fair value of derivatives
 
4,844

 
8,481

 
Related to natural gas marketing
 
Fair value of derivatives
 
(1
)
 

 
 
 
 
 
32,230

 
36,644

Total derivative liabilities
 
 
 
 
$
62,579

 
$
66,642

 
 
 
 
 
 
 
 
__________
(1)    As of June 30, 2011, and December 31, 2010, none of our derivative instruments were designated as hedges.
(2)     Our balance sheets include a corresponding payable to our affiliated partnerships of $14.0 million and $20.3 million as of June 30, 2011, and December 31, 2010, respectively.
(3)     Our balance sheets include a corresponding receivable from our affiliated partnerships of $9.5 million and $14.6 million as of June 30, 2011, and December 31, 2010, respectively.
    
    

12

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.

 
 
2011
 
2010
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)
Three Months Ended June 30,
 
 
 
 
 
 
 
 
 
 
 
 
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
763

 
$
1,040

 
$
1,803

 
$
7,503

 
$
390

 
$
7,893

Unrealized gains (losses)
 
(763
)
 
19,497

 
18,734

 
(7,503
)
 
11,867

 
4,364

Total commodity price risk management gain, net (1)
 
$

 
$
20,537

 
$
20,537

 
$

 
$
12,257

 
$
12,257

Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
473

 
$
19

 
$
492

 
$
1,984

 
$
(179
)
 
$
1,805

Unrealized gains (losses)
 
(473
)
 
456

 
(17
)
 
(1,984
)
 
(580
)
 
(2,564
)
Total sales from natural gas marketing (2)
 
$

 
$
475

 
$
475

 
$

 
$
(759
)
 
$
(759
)
Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
(370
)
 
$
(31
)
 
$
(401
)
 
$
(1,747
)
 
$
138

 
$
(1,609
)
Unrealized gains (losses)
 
370

 
(436
)
 
(66
)
 
1,747

 
664

 
2,411

Total cost of natural gas marketing (2)
 
$

 
$
(467
)
 
$
(467
)
 
$

 
$
802

 
$
802

 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30,
 
 
 
 
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
6,612

 
$
(1,021
)
 
$
5,591

 
$
21,604

 
$
9,213

 
$
30,817

Unrealized gains (losses)
 
(6,612
)
 
(2,324
)
 
(8,936
)
 
(21,604
)
 
46,266

 
24,662

Total commodity price risk management gain (loss), net (1)
 
$

 
$
(3,345
)
 
$
(3,345
)
 
$

 
$
55,479

 
$
55,479

Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
1,373

 
$
261

 
$
1,634

 
$
1,481

 
$
1,383

 
$
2,864

Unrealized gains (losses)
 
(1,373
)
 
339

 
(1,034
)
 
(1,481
)
 
2,429

 
948

Total sales from natural gas marketing (2)
 
$

 
$
600

 
$
600

 
$

 
$
3,812

 
$
3,812

Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized losses
 
$
(1,076
)
 
$
(285
)
 
$
(1,361
)
 
$
(1,329
)
 
$
(1,376
)
 
$
(2,705
)
Unrealized gains (losses)
 
1,076

 
(200
)
 
876

 
1,329

 
(2,238
)
 
(909
)
Total cost of natural gas marketing (2)
 
$

 
$
(485
)
 
$
(485
)
 
$

 
$
(3,614
)
 
$
(3,614
)
 
 
 
 
 
 
 
 
 
 
 
 
 
__________
(1)     Represents realized and unrealized gains and losses on derivative instruments related to natural gas and crude oil sales.
(2)     Represents realized and unrealized gains and losses on derivative instruments related to natural gas marketing.

Concentration of Credit Risk. We make extensive use of over-the-counter derivative instruments that enable us to manage a portion of our exposure to price volatility from producing and marketing 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 was not significant.

    

13

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

The following table presents the derivative counterparties that expose us to credit risk.

Counterparty Name
 
Fair Value of
Derivative Assets
As of June 30, 2011
 
 
(in thousands)
 
 
 
JPMorgan Chase Bank, N.A. (1)
 
$
35,423

Crèdit Agricole CIB (1)
 
21,978

Wells Fargo Bank, N.A. (1)
 
12,998

Various (2)
 
2,944

Total
 
$
73,343

 
 
 
________________________
(1)Major lender in our credit facility, see Note 7.
(2)Represents a total of 19 counterparties, including three lenders in our credit facility.

NOTE 5 - PROPERTIES AND EQUIPMENT

The following table presents the components of properties and equipment, net.

 
June 30, 2011
 
December 31, 2010
 
(in thousands)
Properties and equipment, net:
 
 
 
Natural gas and crude oil properties
 
 
 
Proved
$
1,599,926

 
$
1,429,667

Unproved
72,663

 
79,053

Total natural gas and crude oil properties
1,672,589

 
1,508,720

Pipelines and related facilities
34,110

 
34,262

Transportation and other equipment
33,209

 
32,410

Land, buildings and leasehold improvements
14,514

 
13,379

Construction in progress
63,351

 
42,128

 
1,817,773

 
1,630,899

Accumulated DD&A
(573,360
)
 
(510,861
)
Properties and equipment, net
$
1,244,413

 
$
1,120,038

 
 
 
 

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 enacted 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 and six months ended 2011 was 27.2% (provision on income) and 43.8% (benefit on loss), respectively, compared to 36.1% (benefit on loss) and 37.7% (provision on income) for the three and six months ended 2010, respectively. Since our full year forecasted loss is less than our loss for the six months ended 2011, the amount of tax benefit we can record on our year to date loss is limited. The tax benefit limitation for the six months ended 2011 was $1.9 million compared to a $1.5 million limitation for the three months ended March 31, 2011. The effective tax rate for the six months ended 2010 was for a provision on income, not a tax benefit on loss, therefore there was no limitation affecting the 2010 rate. The effective tax rate differs from the statutory rate primarily due to net permanent deductions, largely percentage depletion, increasing the tax benefit on loss for this six month-period, while decreasing the tax provision on pretax income for the same prior year period. During the three months ended 2011, we recorded a net discrete tax benefit of $0.6 million primarily due to a reduction of our liability for uncertain tax benefits.

As of June 30, 2011, we had a gross liability for unrecognized tax benefits of $0.6 million compared to $1.1 million at December 31, 2010. If recognized, $0.5 million of this liability would affect our effective tax rate. This liability is reflected in other accrued expenses on our accompanying balance sheet. In July 2011, the Internal Revenue Service ("IRS") completed its examination of our 2007, 2008 and 2009 tax years. During the three months ended 2011, we reduced our liability by $0.6 million for uncertain tax benefits that were resolved without change by the completion of the IRS examination and reduced the liability by $0.1 million due to the expiration of the statute of limitations

14

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

related to another tax position. During the six months ended 2011, we increased the liability by $0.2 million for tax positions of the current year. We expect our remaining liability for uncertain tax positions to decrease in the next 12 months as a remaining uncertain tax position is reviewed under the IRS Compliance Assurance Process.

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.

NOTE 7 - LONG-TERM DEBT

Long-term debt consists of the following:
 
 
June 30, 2011
 
December 31, 2010
 
(in thousands)
Senior notes
 
 
 
3.25% Convertible senior notes due 2016:
 
 
 
Principal amount
$
115,000

 
$
115,000

Unamortized discount
(18,368
)
 
(20,252
)
3.25% Convertible senior notes due 2016, net of discount
96,632

 
94,748

12% Senior notes due 2018:


 


Principal amount
203,000

 
203,000

Unamortized discount
(1,908
)
 
(2,053
)
12% Senior notes due 2018, net of discount
201,092

 
200,947

Total senior notes
297,724

 
295,695

Credit facilities
 
 
 
Corporate
8,500

 

PDCM
7,900

 

Total credit facilities
16,400

 

Total long-term debt
$
314,124

 
$
295,695

 
 
 
 
    
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, which commenced on May 15, 2011. 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 June 30, 2011, 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 as of November 5, 2010, as amended last on May 6, 2011, with an aggregate revolving commitment or borrowing base of $350 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.
    

15

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

Our credit facility borrowing base is subject to size redetermination semiannually based on a valuation of our natural gas and crude oil 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 natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 26 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 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.

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 would fall below the outstanding balance. The credit facility contains covenants customary for agreements of this type.

Through May 26, 2011, we had outstanding an undrawn $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider. This letter of credit reduced the amount of available funds under our credit facility by an equal amount. We paid 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 May 26, 2011) for the period the letter of credit remained outstanding. The letter of credit was originally set to expire on May 22, 2012. On May 27, 2011, we were required to replace the original letter of credit with a new letter of credit. As of June 30, 2011, for administrative reasons, the new letter of credit was not yet final; however, it was completed and outstanding as of July 25, 2011, and therefore has been included in this report as if outstanding, but undrawn, for available liquidity calculations as of June 30, 2011. There were no significant changes from the original letter of credit.

As of June 30, 2011, we had drawn $8.5 million from our credit facility compared to no outstanding draws as of December 31, 2010. We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our credit facility. As of June 30, 2011, the available funds under our credit facility, assuming the $18.7 million irrevocable standby letter of credit was in effect, were $322.8 million. The weighted average borrowing rate on our credit facility was 0.7% per annum as of June 30, 2011.

PDCM Credit Facility. PDCM has a credit facility dated as of April 30, 2010, as amended on April 20, 2011, with an aggregate revolving commitment or borrowing base of $40 million. In addition to the increase in borrowing base, the first amendment permits PDCM to enter into swap agreements on new properties which were not included in the most recent reserve report and which have been producing for at least 30 days. 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 June 30, 2011, PDCM had drawn $15 million from its credit facility, of which our proportionate share was $7.9 million. As of December 31, 2010, there were no amounts outstanding related to this credit facility. The weighted average borrowing rate on PDCM's credit facility was 1.8% per annum as of June 30, 2011.

As of June 30, 2011, 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, 2010 (1)
$
28,047

Change in ownership interest of PDCM
(485
)
Obligations incurred with development activites and assumed with acquisitions
847

Accretion expense
798

Obligations discharged with disposal of properties and asset retirements
(221
)
Revisions in estimated cash flows
(322
)
Balance at June 30, 2011
28,664

Less current portion
(250
)
Long-term portion
$
28,414

 
 
__________
(1)    Includes $0.2 million as of December 31, 2010, related to assets held for sale.

16

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


NOTE 9 - COMMITMENTS AND CONTINGENCIES

Merger Agreements. On June 20, 2011, pursuant to our previously announced partnership acquisition plan, we entered into separate merger agreements with five of our affiliated partnerships: PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership, PDC 2003-D Limited Partnership and PDC 2002-D Limited Partnership (collectively, the "2003/2002-D Partnerships"). We serve as the managing general partner of each of the 2003/2002-D Partnerships. Pursuant to each merger agreement, if the merger is approved by the holders of a majority of the limited partnership units held by limited partners of that partnership not owned by us (the "non-affiliated investor partners"), as well as the satisfaction of other customary closing conditions, then we will acquire such partnerships. If all five partnerships are acquired, we expect to pay an aggregate of approximately $29.5 million to the non-affiliated investor partners for the limited partnership units of these partnerships. On June 23, 2011, we filed the preliminary proxy statements with the SEC and anticipate, upon clearance by the SEC, that the definitive proxy statements are anticipated to be mailed to investors in August 2011. If the required approvals are received, we expect the mergers to be completed in the fourth quarter of 2011. We expect to finance the acquisition of the 2003/2002-D Partnerships by borrowing funds under our revolving credit facility. There can be no assurance that we will be successful in the acquisition of the 2003/2002-D Partnerships, individually or collectively, or on terms acceptable to us.
    
Drilling Rig Contract. In order to secure the services of a drilling rig, in August 2010, PDCM entered into a commitment with a drilling contractor for the services of a drilling rig. The commitment expires in October 2012. During the first quarter of 2011, included in production costs in the statement of operations, we recorded a charge of $0.5 million related to our proportionate share of rig laydown costs. As of June 30, 2011, our proportionate share of PDCM's related maximum commitment through October 2012 was $4.5 million.

Firm Transportation Agreements. We have entered 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 our joint venture and affiliated partnerships. We record in our financial statements only our share of costs based upon our working interest in the wells; however, the costs of all volume shortfalls will be borne by PDC.

As of June 30, 2011, we have a liability in the amount of $3.1 million included in other liabilities on the balance sheet related to an agreement in the Piceance Basin. On July 27, 2011, we entered into an amendment with the unrelated third party subject to this agreement and as a result, the accrued liability as of June 30, 2011, will be reduced during the third quarter of 2011 with no cash payment by us required. The amendment did not extend the expiration date of the original agreement. The table below does not include the impact of this amendment. Including the impact of this amendment, our volume requirements for the Piceance Basin would be 18,000 MMcf, 19,814 MMcf, 39,252 MMcf, 33,201 MMcf and 126,265 MMcf for the 12 months ending June 30, 2012, 2013, 2014, 2015 and 2016 through expiration, respectively, for a total of 236,532 MMcf.

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 June 30,
 
 
 
 
Area
 
2012
 
2013
 
2014
 
2015
 
2016 Through
Expiration
 
Total
 
Expiration
Date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Piceance Basin
 
32,613

 
32,577

 
28,182

 
22,131

 
60,759

 
176,262

 
May 31, 2021
Appalachian Basin (1)
 
5,150

 
14,324

 
15,992

 
15,992

 
110,665

 
162,123

 
August 31, 2022
NECO
 
2,745

 
1,825

 
1,825

 
1,825

 
2,745

 
10,965

 
December 31, 2016
Total
 
40,508

 
48,726

 
45,999

 
39,948

 
174,169

 
349,350

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dollar commitment
(in thousands)
 
$
19,867

 
$
24,118

 
$
22,704

 
$
19,527

 
$
82,171

 
$
168,387

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
_____________
(1)
Includes a precedent agreement that becomes effective when a planned pipeline is placed in service, currently expected to be September 2012 and represents 8,823 MMcf of the total MMcf presented for the year ending June 30, 2013, 10,629 MMcf for each of the years ending June 30, 2014 and 2015, respectively, and 76,265 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.

    

17

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

Litigation. The Company is involved in various legal proceedings that it considers normal to 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.

    
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. On October 27, 2010, the state court set a trial date of April 2012.

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, a written settlement agreement was signed confirming these terms and on June 30, 2011, the state court granted initial approval of the settlement agreement, subject to notice to class members and final court approval. As of June 30, 2011, the total settlement amount of $8.7 million was accrued and included in other accrued expenses on the accompanying balance sheet. A related escrow account was fully funded on July 22, 2011.

Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures in place 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 assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of June 30, 2011, and December 31, 2010, we had accrued environmental liabilities in the amount of $2.3 million and $1.7 million, respectively, included in other accrued expenses on the balance sheet. We are not currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on our accompanying 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 where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the respective partnership's 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 June 30, 2011, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $5 million. We believe we have adequate liquidity to meet this obligation. For the six months ended 2011, amounts paid for the repurchase of partnership units pursuant to this provision were immaterial.
    
Employment Agreements with Executive Officers. With the exception of our Chief Executive Officer, 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. We are currently in the process of preparing an employment agreement with our Chief Executive Officer.
    
If, within two years following a change of 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 (what is referred to as a "double trigger"), 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. For one executive, in this calculation, the target bonus will be used as the minimum value for the first two years of employment. 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 Internal Revenue Code ("IRC") 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) retirement benefits earned under the current and/or previous agreements, (iv) continued coverage under our medical plan at the Company's cost for the federal COBRA health continuation coverage period and (v) 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 accelerated.
 
    

18

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

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 plus a partial year bonus, 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 is entitled to receive certain benefits. For this purpose, the definition of "disability" corresponds to the definition under IRC 409A and the supporting Treasury regulations. The benefits will (i) in the case of death 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.

See Note 13 for a discussion related to the separation agreement entered into with our former chief executive officer during the three months ended 2011.

Partnership Casualty Losses. As Managing General Partner of numerous partnerships, we have a potential liability for casualty losses in excess of the partnership assets and insurance. We believe the casualty insurance coverage that we and our subcontractors carry is adequate to meet this potential liability.

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 June 30,
 
Six Months Ended June 30,
 
 
2011 (1)
 
2010
 
2011 (1)
 
2010
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
Total stock-based compensation expense
 
$
4,004

 
$
1,216

 
$
5,549

 
$
2,221

Income tax benefit
 
(1,521
)
 
(467
)
 
(2,108
)
 
(852
)
Net income (loss) impact
 
$
2,483

 
$
749

 
$
3,441

 
$
1,369

 
 
 
 
 
 
 
 
 
__________
(1)
Includes a total of $2.5 million, pretax, related to a separation agreement with our former chief executive officer.

Stock Appreciation Rights ("SARs")

In March 2011, the Compensation Committee of our Board of Directors (the "Compensation Committee") awarded 31,552 SARs to our executive officers. The SARs will vest ratably over a three-year period and may be exercised at any point after vesting through March 2021. Pursuant to the terms of the awards, upon exercise, the executives 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.
    
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.

 
Six Months Ended
 
June 30, 2011
 
 
Expected term of the award
6 years

Risk-free interest rate
2.5
%
Volatility
60.2
%
Weighted average grant date fair value per share
$
25.22


19

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

    
The following table presents the changes in our SARs for the six months ended 2011.
 
 
Number of
Shares
Underlying
SARs
 
Grant Date Market Price
Per Share
 
Average Remaining Contractual
Term
(in years)
 
Aggregate Intrinsic
Value
(in thousands)
 
 
 
 
 
 
 
 
 
Outstanding at December 31, 2010
 
57,282

 
$
24.44

 
9.3

 
$

Awarded
 
31,552

 
43.95

 
9.7

 

Outstanding at June 30, 2011
 
88,834

 
31.37

 
5.3

 
313

Vested and expected to vest at June 30, 2011
 
84,851

 
31.27

 
5.0

 
302

Exercisable at June 30, 2011
 
48,999

 
29.61

 
2.1

 
197

 
 
 
 
 
 
 
 
 

Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, 29,906 SARs were accelerated to vest, resulting in the acceleration of $0.6 million in stock-based compensation expense. The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of June 30, 2011, was $0.6 million. The cost is expected to be recognized over a weighted average period of 1.8 years.

Restricted Stock Awards

Time-Based Awards. In March 2011, the Compensation Committee awarded a total of 43,256 time-based restricted shares to our executive officers that vest ratably over a three-year period ending on March 12, 2014. In June 2011, the Compensation Committee awarded 58,122 time-based restricted shares to our new chief executive officer that vest ratably over a three-year period ending on June 10, 2014, and 21,798 time-based restricted shares to our non-employee directors that vest ratably over a three-year period ending on July 1, 2014.

Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, the vesting of 64,442 time-based restricted shares was accelerated, resulting in the acceleration of $1.9 million in stock-based compensation expense. 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 June 30, 2011, was $10.0 million. This cost is expected to be recognized over a weighted average period of 2.1 years.

The following table presents the changes in non-vested time-based awards for the six months ended 2011.
 
 
Shares
 
Weighted Average
Grant-Date
Fair Value per Share
 
 
 
 
 
Non-vested at December 31, 2010
 
525,715

 
$
25.53

Granted
 
149,365

 
37.42

Vested
 
(183,639
)
 
28.37

Forfeited
 
(13,580
)
 
24.51

Non-vested at June 30, 2011
 
477,861

 
28.18

 
 
 
 
 

 
As of / Six Months Ended
 
June 30, 2011
 
(in thousands, except per share data)
 
 
Total intrinsic value of time-based awards vested
$
7,185

Total intrinsic value of time-based awards non-vested
14,293

Market price per common share
29.91


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.

    

20

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

In March 2011, the Compensation Committee awarded a total of 13,531 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 11 peer companies. The shares are measured over a three-year period ending on December 31, 2013, 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.

 
 
Six Months Ended
 
 
June 30, 2011
 
 
 
Expected term of award
 
3 years

Risk-free interest rate
 
1.1
%
Volatility
 
74.2
%
Weighted average grant date fair value per share
 
$
58.53


Expected volatility was based on a blend of our historical and implied 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.

The following table presents the change in non-vested market-based awards for the six months ended 2011.

 
Shares
 
Weighted Average
Grant-Date
Fair Value per Share
 
 
 
 
Non-vested at December 31, 2010
79,550

 
$
32.52

Granted
13,531

 
58.53

Vested
(4,109
)
 
6.47

Forfeited
(21,927
)
 
34.32

Non-vested at June 30, 2011
67,045

 
38.78

 
 
 
 

Pursuant to a separation agreement with our former chief executive officer and the original terms of the award, during the three months ended 2011, the vesting of 4,109 market-based restricted shares was accelerated and 21,927 market-based restricted shares were forfeited. The impact on stock-based compensation for the vesting and forfeiture of these market-based restricted shares was immaterial. 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 June 30, 2011, was $0.4 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 six months ended June 30, 2011, we acquired 38,635 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 35,335 shares were retired.



21

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

NOTE 11 - EARNINGS PER SHARE

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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding - basic
23,491

 
19,213

 
23,460

 
19,202

Dilutive effect of share-based compensation:
 
 
 
 
 
 
 
Restricted stock
181

 

 

 
86

SARs
48

 

 

 

Non employee director deferred compensation
3

 

 

 
8

Weighted average common and common share equivalents outstanding - diluted
23,723

 
19,213

 
23,460

 
19,296

 
 
 
 
 
 
 
 

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 June 30,
 
Six Months Ended June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Weighted average common share equivalents excluded from diluted earnings
 
 
 
 
 
 
 
per share due to their anti-dilutive effect:
 
 
 
 
 
 
 
Restricted stock
102

 
434

 
587

 
181

Stock options
10

 
10

 
10

 
10

SARs
32

 
57

 
77

 
57

Non employee director deferred compensation

 
8

 
3

 

Total anti-dilutive common share equivalents
144

 
509

 
677

 
248

 
 
 
 
 
 
 
 

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 table above does not include those shares issuable upon conversion as the average share price of our common stock did not exceed the conversion price during the three and six months ended 2011.

NOTE 12 - DIVESTITURES AND DISCONTINUED OPERATIONS

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 our Board of Directors' (the "Board") approval and, in December 2010, we effected a letter of intent with an unrelated third party. 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 North Dakota assets were reclassified as held for sale as of December 31, 2010, and the results of operations related to those assets have been separately reported as discontinued operations in the accompanying financial statements for all periods presented. 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.

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 prior period had no impact upon previously reported net earnings, the statement of operations and operational data present the revenues, expenses and production volumes that were reclassified from the specified statement of operations line items to discontinued operations.

The following table presents statement of operations data related to our discontinued operations. There was no activity recorded for discontinued operations for the three months ended 2011. The three and six months ended 2010, in addition to the discontinued operations data of our North Dakota assets, includes operations data related to the July 2010 divestiture of our Michigan assets.


22

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

 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Statement of Operations - Discontinued Operations
 
2010
 
2011
 
2010
 
 
(dollars in thousands)
Revenues
 
 
 
 
 
 
Natural gas, NGL and crude oil sales
 
$
1,995

 
$
447

 
$
4,536

Sales from natural gas marketing
 
1,136

 

 
2,760

Well operations, pipeline income and other
 
146

 
10

 
402

Total revenues
 
3,277

 
457

 
7,698

 
 
 
 
 
 
 
Costs, expenses and other
 
 
 
 
 
 
Production costs
 
864

 
132

 
1,579

Cost of natural gas marketing
 
1,197

 

 
2,728

Impairment of proved natural gas and oil properties
 
4,506

 

 
4,506

Depreciation, depletion and amortization
 
533

 

 
1,464

Gain on sale of properties and equipment
 

 
(3,854
)
 

Total costs, expenses and other
 
7,100

 
(3,722
)
 
10,277

 
 
 
 
 
 
 
Income (loss) from discontinued operations
 
(3,823
)
 
4,179

 
(2,579
)
Provision (benefit) for income taxes
 
(1,510
)
 
1,559

 
(1,063
)
Income (loss) from discontinued operations, net of tax
 
$
(2,313
)
 
$
2,620

 
$