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EX-32.1 - SECTION 906 CERT - PDC ENERGY, INC.ex321.htm
EX-31.2 - SECTION 302 CERT CFO - PDC ENERGY, INC.ex312.htm
EX-31.1 - SECTION 302 CERT CEO - PDC ENERGY, INC.ex311.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - PDC ENERGY, INC.ex121.htm
EX-23.1 - CONSENT OF PETROLEUM CONSULTANTS - PDC ENERGY, INC.pdcex231.htm
EX-99.1 - REPORT OF PETROLEUM CONSULTANTS - PDC ENERGY, INC.pdcex991.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-Q
 
x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2010 
 
or
 
o Transition Report Pursuant to Section 13 of 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 x     No o
 
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 £   No £
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer  £
Accelerated filer  x
 
Non-accelerated filer  £
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 o  No x
 
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 19,272,750 shares of the Company's Common Stock ($.01 par value) were outstanding as of October 29, 2010.
 
EXPLANATORY NOTE
Effective July 15, 2010, Petroleum Development Corporation began conducting business as PDC Energy. A new logo and corporate identity accompanied this change. Our common stock continues to trade on the NASDAQ Global Select Market under the ticker symbol PETD. We continue to maintain our website address, www.petd.com, which reflects the new PDC Energy name and brand identity. This change reflects the transitioning in our business model, from a company that was predominately a sponsor of limited partnerships to a natural gas and oil company that explores for and acquires, develops, produces and markets natural gas and oil resources. We believe that the name PDC Energy more fully portrays the range of business activities in which we engage.

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

INDEX
 
PART I – FINANCIAL INFORMATION
 
 
 
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.
 
 
 
 
 
 
 

1

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. 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, which include statements of estimated natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and our management's strategies, plans and objectives. However, these 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 risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas and 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, worldwide demand and commodity prices for natural gas and oil;
•    
changes in estimates of proved reserves;
•    
declines in the values of our natural gas and oil properties resulting in impairments;
•    
the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil reserves;
•    
our ability to acquire leases, drilling rigs, supplies and services at reasonable prices;
•    
the availability and cost of capital to us, including the availability of funding for the consideration payable by us to consummate the prospective mergers of the four 2004 partnerships;
•    
the timing and closing, if consummated, of the mergers of the four 2004 partnerships;
•    
reductions in the borrowing base under our credit facility;
•    
risks incident to the drilling and operation of natural gas and oil wells;
•    
future production and development costs;
•    
the availability of sufficient pipeline and other transportation facilities to carry our production and the impact of these facilities on price;
•    
the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America ("U.S.");
•    
changes in environmental laws and the regulations and enforcement related to those laws;
•    
the identification of and severity of environmental events and governmental responses to the events;
•    
the effect of natural gas and oil derivative activities;
•    
conditions in the capital markets; and
•    
losses possible from pending or future litigation.
 
Further, we urge you to carefully review and consider the cautionary statements made in this report, our annual report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission ("SEC") on March 4, 2010, as amended August 31, 2010 ("2009 Form 10-K"), and our other filings with the SEC and public disclosures. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date made. Other than as required under the securities laws, 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.
 
 
 
REFERENCES
 
Unless the context otherwise requires, references to "PDC Energy," "the Company," "we," "us," "our," "ours" or "ourselves" in this report refer to the registrant, Petroleum Development Corporation ("PDC"), together with its wholly owned subsidiaries, an entity in which it has a controlling financial interest and its proportionate share of affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture with Lime Rock Partners.
 
References to "the three months ended 2010" and "the nine months ended 2010" refer to the three or nine months ended September 30, 2010, as applicable. References to "the three months ended 2009" and "the nine months ended 2009" refer to the three or nine months ended September 30, 2009, as applicable.

2

PART I - FINANCIAL INFORMATION
Item 1.  Financial Statements
PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Balance Sheets
(unaudited; in thousands, except share data)
 
September 30, 2010
 
December 31, 2009*
Assets
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
$
13,299
 
 
$
31,944
 
Restricted cash
2,478
 
 
2,490
 
Accounts receivable, net
49,013
 
 
56,491
 
Accounts receivable affiliates
11,753
 
 
7,956
 
Fair value of derivatives
52,605
 
 
42,223
 
Income tax receivable
 
 
27,728
 
Prepaid expenses and other current assets
1,878
 
 
8,538
 
Total current assets
131,026
 
 
177,370
 
Properties and equipment, net
1,029,011
 
 
979,373
 
Assets held for sale
 
 
28,820
 
Fair value of derivatives
54,949
 
 
20,228
 
Accounts receivable affiliates
12,067
 
 
15,473
 
Other assets
23,511
 
 
29,063
 
Total Assets
$
1,250,564
 
 
$
1,250,327
 
 
 
 
 
Liabilities and Equity
 
 
 
 
Liabilities
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
$
42,104
 
 
$
36,845
 
Accounts payable affiliates
12,788
 
 
13,015
 
Production tax liability
15,099
 
 
24,849
 
Fair value of derivatives
22,558
 
 
20,208
 
Funds held for distribution
27,654
 
 
28,256
 
Other accrued expenses
20,880
 
 
21,261
 
Total current liabilities
141,083
 
 
144,434
 
Long-term debt
302,374
 
 
280,657
 
Deferred income taxes
182,188
 
 
178,012
 
Asset retirement obligation
26,339
 
 
29,314
 
Fair value of derivatives
36,969
 
 
48,779
 
Accounts payable affiliates
17,531
 
 
5,996
 
Other liabilities
23,234
 
 
24,542
 
Total liabilities
729,718
 
 
711,734
 
 
 
 
 
COMMITMENTS AND CONTINGENT LIABILITIES
 
 
 
 
 
 
 
Equity
 
 
 
 
Shareholders' equity:
 
 
 
 
Preferred shares, par value $.01 per share;  authorized 50,000,000 shares; issued: none
 
 
 
Common shares, par value $.01 per share; authorized 100,000,000 shares; issued: 19,274,031 shares for 2010 and 19,242,219 for 2009
193
 
 
192
 
Additional paid-in capital
69,692
 
 
64,406
 
Retained earnings
450,983
 
 
426,629
 
Treasury shares, at cost; 8,273 shares for 2010 and for 2009
(312
)
 
(312
)
Total shareholders' equity
520,556
 
 
490,915
 
Noncontrolling interest
290
 
 
47,678
 
Total equity
520,846
 
 
538,593
 
Total Liabilities and Equity
$
1,250,564
 
 
$
1,250,327
 
*Derived from audited 2009 balance sheet.
 
See accompanying notes to condensed consolidated financial statements.

3

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2010
 
2009
 
2010
 
2009
Revenues:
 
 
 
 
 
 
 
Natural gas and oil sales
$
48,070
 
 
$
42,871
 
 
$
156,133
 
 
$
121,440
 
Sales from natural gas marketing
18,337
 
 
11,062
 
 
53,613
 
 
43,200
 
Commodity price risk management gain (loss), net
19,029
 
 
(13,813
)
 
74,508
 
 
(13,414
)
Well operations, pipeline income and other
2,173
 
 
2,264
 
 
6,941
 
 
7,698
 
Total revenues
87,609
 
 
42,384
 
 
291,195
 
 
158,924
 
 
 
 
 
 
 
 
 
Costs, expenses and other:
 
 
 
 
 
 
 
 
 
Natural gas and oil production and well operations costs
16,685
 
 
14,705
 
 
48,217
 
 
44,242
 
Cost of natural gas marketing
18,300
 
 
10,179
 
 
52,830
 
 
41,420
 
Exploration expense
3,737
 
 
6,586
 
 
13,985
 
 
15,363
 
General and administrative expense
10,426
 
 
9,627
 
 
30,975
 
 
36,505
 
Depreciation, depletion and amortization
28,219
 
 
31,935
 
 
82,992
 
 
99,080
 
Gain on sale of leaseholds
(57
)
 
 
 
(153
)
 
(120
)
Total costs, expenses and other
77,310
 
 
73,032
 
 
228,846
 
 
236,490
 
 
 
 
 
 
 
 
 
Operating income (loss)
10,299
 
 
(30,648
)
 
62,349
 
 
(77,566
)
Interest income
21
 
 
208
 
 
60
 
 
240
 
Interest expense
(8,174
)
 
(9,221
)
 
(23,646
)
 
(27,024
)
 
 
 
 
 
 
 
 
Income (loss) from continuing operations before income taxes
2,146
 
 
(39,661
)
 
38,763
 
 
(104,350
)
Provision (benefit) for income taxes
(1,020
)
 
(14,707
)
 
12,746
 
 
(39,795
)
Income (loss) from continuing operations
3,166
 
 
(24,954
)
 
26,017
 
 
(64,555
)
Income (loss) from discontinued operations, net of tax
188
 
 
179
 
 
(1,729
)
 
966
 
Net income (loss)
3,354
 
 
(24,775
)
 
24,288
 
 
(63,589
)
Less:  net loss attributable to noncontrolling interest
(5
)
 
(299
)
 
(66
)
 
(331
)
Net income (loss) attributable to shareholders
$
3,359
 
 
$
(24,476
)
 
$
24,354
 
 
$
(63,258
)
 
 
 
 
 
 
 
 
Amounts attributable to shareholders:
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
3,171
 
 
$
(24,655
)
 
$
26,083
 
 
$
(64,224
)
Income (loss) from discontinued operations
188
 
 
179
 
 
(1,729
)
 
966
 
Net income (loss) attributable to shareholders
$
3,359
 
 
$
(24,476
)
 
$
24,354
 
 
$
(63,258
)
 
 
 
 
 
 
 
 
Earnings (loss) per share attributable to shareholders:
 
 
 
 
 
 
 
 
 
Basic
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.16
 
 
$
(1.45
)
 
$
1.36
 
 
$
(4.13
)
Income (loss) from discontinued operations
0.01
 
 
0.01
 
 
(0.09
)
 
0.06
 
Net income (loss) attributable to shareholders
$
0.17
 
 
$
(1.44
)
 
$
1.27
 
 
$
(4.07
)
 
 
 
 
 
 
 
 
Diluted
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
$
0.16
 
 
$
(1.45
)
 
$
1.35
 
 
$
(4.13
)
Income (loss) from discontinued operations
0.01
 
 
0.01
 
 
(0.09
)
 
0.06
 
Net income (loss) attributable to shareholders
$
0.17
 
 
$
(1.44
)
 
$
1.26
 
 
$
(4.07
)
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
19,250
 
 
16,962
 
 
19,218
 
 
15,530
 
Diluted
19,406
 
 
16,962
 
 
19,319
 
 
15,530
 
 
See accompanying notes to condensed consolidated financial statements.

4

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)
 
Nine Months Ended
 
September 30,
 
2010
 
2009
Cash flows from operating activities:
 
 
 
Net income (loss)
$
24,288
 
 
$
(63,589
)
Adjustments to net income (loss) to reconcile to cash provided by operating activities:
 
 
 
 
Deferred income taxes
10,835
 
 
(33,529
)
Depreciation, depletion and amortization
84,086
 
 
100,796
 
Exploratory dry hole costs
4,057
 
 
1,078
 
Amortization and impairment of unproved properties
2,211
 
 
4,760
 
Impairment of proved natural gas and oil properties
4,666
 
 
 
Unrealized loss (gain) on derivative transactions
(36,056
)
 
95,735
 
Other
7,728
 
 
9,455
 
Changes in assets and liabilities
14,977
 
 
(14,735
)
Net cash provided by operating activities
116,792
 
 
99,971
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
Capital expenditures
(106,795
)
 
(124,821
)
Acquisitions
(85,511
)
 
 
Proceeds from the sale of assets
23,250
 
 
378
 
Deconsolidation/change in ownership effect on cash and cash equivalents
(3,472
)
 
 
Net cash used in investing activities
(172,528
)
 
(124,443
)
 
 
 
 
Cash flows from financing activities:
 
 
 
 
Proceeds from credit facility
244,000
 
 
226,000
 
Repayment of credit facility
(222,500
)
 
(269,500
)
Payment of debt issuance costs
(205
)
 
(8,980
)
Proceeds from sale of equity
 
 
48,454
 
Excess tax benefits from stock-based compensation
215
 
 
 
Change in ownership interest in PDCM
16,173
 
 
 
Purchase of treasury stock
(592
)
 
(312
)
Net cash provided by (used in) financing activities
37,091
 
 
(4,338
)
 
 
 
 
Net decrease in cash and cash equivalents
(18,645
)
 
(28,810
)
Cash and cash equivalents, beginning of period
31,944
 
 
50,950
 
Cash and cash equivalents, end of period
$
13,299
 
 
$
22,140
 
 
 
 
 
 
 
 
 
Supplemental cash flow information:
 
 
 
 
Cash payments (receipts) for:
 
 
 
Interest, net of capitalized interest
$
28,651
 
 
$
30,155
 
Income taxes, net of refunds
(26,998
)
 
(3,522
)
Non-cash investing activities:
 
 
 
 
Change in accounts payable related to purchases of properties and equipment
7,108
 
 
(36,383
)
Change in asset retirement obligation, with a corresponding increase to natural gas and oil properties, net of disposals
2,239
 
 
260
 
See Note 14 for non-cash transactions related to PDCM
 
 
 
 
See accompanying notes to condensed consolidated financial statements.

5

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)
Notes to Condensed Consolidated Financial Statements
September 30, 2010
(unaudited)

 
 
 
1.    
NATURE OF OPERATIONS AND BASIS OF PRESENTATION
 
We are a domestic independent natural gas and oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas and oil. As of September 30, 2010, we owned an interest in and operated approximately 5,000 gross wells located primarily in the Rocky Mountain Region and Appalachian Basin. We are engaged in two primary business segments: natural gas and oil sales and 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 PDCM and our affiliated partnerships. All material intercompany accounts and transactions have been eliminated in consolidation. We account for our investment in PDCM and our interests in natural gas and oil limited partnerships under the proportionate consolidation method. Accordingly, our accompanying condensed consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of 34 entities which we proportionately consolidate. Our proportionate share of all significant transactions between us and these entities has been eliminated. See Notes 2 and 14 for the impact of new accounting changes on the consolidation of PDCM, a variable interest entity, on January 1, 2010.
 
In our opinion, the accompanying financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation 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 2009 Form 10-K. Our accounting policies are described in the Notes to Consolidated Financial Statements in our 2009 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the nine months ended September 30, 2010, and the cash flows for the same period, are not necessarily indicative of the results to be expected for the full year or any other future period.
 
Certain prior year amounts in the accompanying financial statements and related notes have been reclassified to conform to the current year presentation. The reclassifications are directly related to the sale of our Michigan assets and related 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 the divestiture of our Michigan assets and discontinued operations.
 
2.    
RECENT ACCOUNTING STANDARDS
 
Recently Adopted Accounting Standards
 
Consolidation - Variable Interest Entities. In June 2009, the Financial Accounting Standards Board ("FASB") issued changes regarding an entity's analysis to determine whether any of its variable interests constitute controlling financial interests in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics:
 
•    
the power to direct the activities of a variable interest entity that most significantly impact the entity's economic performance; and
•    
the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity.
 
Additionally, the entity is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance. The guidance also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. We adopted these changes effective January 1, 2010. Upon adoption, we deconsolidated PDCM based upon the fact that power over the activities that

6

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

significantly impact this joint venture is equally shared with our investment partner. No cumulative effect adjustment to retained earnings was recognized upon adoption. See Note 14 for the impact of adoption on our financial statements.
 
Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on our financial statements.
 
Recently Issued Accounting Standards
 
Fair Value Measurements and Disclosures. In January 2010, the 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 will be effective for our financial statements issued for annual reporting periods beginning after December 15, 2010. We do not expect the adoption of this change to have a material impact on our financial statements.
 
3.    FAIR VALUE MEASUREMENTS
 
Derivative Financial Instruments. We measure the fair value of our derivative instruments based upon quoted market prices, where available. Our valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) 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. The methods described above may produce a fair value calculation that may not be indicative of future fair values. Our valuation determination also gives consideration to nonperformance risk on our own liabilities as well as the credit standing of our counterparties. We primarily use financial institutions, which are also major lenders in our credit facility agreement, as counterparties to our derivative contracts. We have evaluated the credit risk of the counterparties holding our derivative assets 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, as of September 30, 2010, the impact of nonperformance risk on the fair value of our derivative assets and liabilities was not significant. Validation of our contracts' fair value is performed internally and 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 these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.
 
The following table presents, by hierarchy level, our derivative financial instruments, including both current and non-current portions, measured at fair value.
 
 
 
September 30, 2010
 
 
December 31, 2009
 
  
Quoted Prices in
Active Markets
(Level 1)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
 
Quoted Prices in
Active Markets
(Level 1)
  
Significant
Unobservable
Inputs
(Level 3)
  
Total
 
  
(in thousands)
Assets:
  
 
 
 
 
 
 
 
 
 
 
 
 
Commodity based derivatives
   
$
75,561
 
   
$
31,937
 
   
$
107,498
 
 
 
$
25,598
 
   
$
36,796
 
   
$
62,394
 
Basis protection derivative contracts
 
 
 
56
 
 
56
 
 
 
 
 
57
 
   
57
 
Total assets
 
75,561
 
 
31,993
 
 
107,554
 
 
 
25,598
 
 
36,853
 
 
62,451
 
Liabilities:
   
 
   
 
   
 
 
 
 
   
 
   
 
Commodity based derivatives
   
70
 
 
10,811
 
   
10,881
 
 
 
3,140
 
 
9,932
 
   
13,072
 
Basis protection derivative contracts
 
 
 
48,646
 
   
48,646
 
 
 
 
 
55,915
 
   
55,915
 
Total liabilities
 
70
 
 
59,457
 
 
59,527
 
 
 
3,140
 
 
65,847
 
 
68,987
 
Net asset (liability)
 
$
75,491
 
 
$
(27,464
)
 
$
48,027
 
 
 
$
22,458
 
 
$
(28,994
)
 
$
(6,536
)
 

7

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

The following table presents the changes in our Level 3 derivative financial instruments measured on a recurring basis.
 
 
 
(in thousands)
 
 
 
Fair value, net liability, as of December 31, 2009
 
$
(28,994
)
Changes in fair value included in statement of operations line items:
 
 
 
Commodity price risk management gain (loss), net
 
28,466
 
Sales from natural gas marketing
 
493
 
Cost of natural gas marketing
 
(5,160
)
Changes in fair value included in balance sheet line items (1):
 
 
Accounts receivable affiliates
 
2,572
 
Accounts payable affiliates
 
(4,465
)
Settlements included in statement of operations line items:
 
 
 
Commodity price risk management gain (loss), net
 
(23,895
)
Sales from natural gas marketing
 
(289
)
Cost of natural gas marketing
 
3,808
 
Fair value, net liability, as of September 30, 2010
 
$
(27,464
)
 
 
 
Changes in unrealized gains (losses) relating to assets (liabilities) still held
 
 
as of September 30, 2010, included in statement of operations line items:
 
 
Commodity price risk management gain (loss), net
 
$
23,114
 
Sales from natural gas marketing activities
 
187
 
Cost of natural gas marketing activities
 
(2,257
)
 
 
$
21,044
 
__________
(1) 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 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 portion of our long-term debt related to our 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, we estimate the fair value of this portion of our long-term debt to be $225.6 million or 111.2% of par value as of September 30, 2010. We determined this valuation based upon measurements of trading activity.
 
We assess our natural gas and oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Certain events, including but not limited to, downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our natural gas and oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets and related liabilities to held for sale. See Note 12. The agreement to sell these assets, a triggering event, required us to perform an impairment test as long lived assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. Since the net carrying value exceeded the net sales price, we were required to recognize an impairment charge by reducing the carrying value of the net assets to reflect the net sales price. As a result, during the nine months ended September 30, 2010, we recorded an impairment charge of $4.7 million related to the sale of our Michigan assets. The impairment charge is reflected

8

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

in discontinued operations in the statement of operations.
 
We estimate the fair value of our plugging and abandonment obligations based on a discounted cash flows analysis. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Changes in estimated asset retirement obligations can result from changes in estimated retirement costs or changes in the estimated timing of payments to settle the asset retirement obligations. See Note 8 for changes in our asset retirement obligations.
 
4.    
DERIVATIVE FINANCIAL INSTRUMENTS
 
As of September 30, 2010, we had derivative instruments in place related to a portion of our anticipated production through 2013 for a total of 39.9 Bcf of natural gas and 2.2 million Bbls of oil. These derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and, related to natural gas marketing, physical sales and purchases.
 
The following table summarizes the line items and fair value amounts of our derivative instruments in the accompanying balance sheets.
 

9

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
 
 
 
 
Fair Value
Derivatives instruments not designated as hedges (1)
 
Balance sheet line item
 
September 30, 2010
 
December 31, 2009
 
 
 
 
 
(in thousands)
Derivative assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
$
49,148
 
 
$
39,107
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
3,408
 
 
3,077
 
 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
49
 
 
39
 
 
 
 
 
 
52,605
 
 
42,223
 
 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
54,737
 
 
19,680
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
205
 
 
530
 
 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
7
 
 
18
 
 
 
 
 
 
54,949
 
 
20,228
 
Total derivative assets (2)
 
$
107,554
 
 
$
62,451
 
 
 
 
 
 
 
 
 
Derivative liabilities:
Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
$
4,505
 
 
$
2,451
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
2,988
 
 
2,626
 
 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
15,064
 
 
15,127
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
1
 
 
4
 
 
 
 
 
 
22,558
 
 
20,208
 
 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
3,203
 
 
7,572
 
 
Related to natural gas marketing
 
Fair value of derivatives
 
185
 
 
423
 
 
Basis protection contracts
 
 
 
 
 
 
 
Related to natural gas and oil sales
 
Fair value of derivatives
 
33,581
 
 
40,784
 
 
 
 
 
 
36,969
 
 
48,779
 
Total derivative liabilities (3)
 
$
59,527
 
 
$
68,987
 
__________
(1)    As of September 30, 2010, and December 31, 2009, none of our derivative instruments were designated as hedges.
(2)    Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships of $28.9 million and $13.4 million as of September 30, 2010, and December 31, 2009, respectively, representing their proportionate share of the derivative assets.
(3)    Includes derivative positions that have been designated to our affiliated partnerships; accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships of $18 million and $21 million as of September 30, 2010, and December 31, 2009, respectively, representing their proportionate share of the derivative liabilities.

10

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
The following table summarizes the impact of our derivative instruments on our accompanying statements of operations for the three and nine months ended September 30, 2010 and 2009.
 
 
 
2010
 
2009
Statement of operations line items
 
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 September 30,
 
 
 
 
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
5,688
 
 
$
1,832
 
 
$
7,520
 
 
$
21,139
 
 
$
685
 
 
$
21,824
 
Unrealized gains (losses)
 
(5,688
)
 
17,197
 
 
11,509
 
 
(21,139
)
 
(14,498
)
 
(35,637
)
Total commodity price risk management gain (loss), net (1)
 
$
 
 
$
19,029
 
 
$
19,029
 
 
$
 
 
$
(13,813
)
 
$
(13,813
)
Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
1,384
 
 
$
222
 
 
$
1,606
 
 
$
1,601
 
 
$
282
 
 
$
1,883
 
Unrealized gains (losses)
 
(1,384
)
 
1,624
 
 
240
 
 
(1,601
)
 
(625
)
 
(2,226
)
Total sales from natural gas marketing (2)
 
$
 
 
$
1,846
 
 
$
1,846
 
 
$
 
 
$
(343
)
 
$
(343
)
Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
(1,169
)
 
$
(280
)
 
$
(1,449
)
 
$
(1,568
)
 
$
(256
)
 
$
(1,824
)
Unrealized gains (losses)
 
1,169
 
 
(1,563
)
 
(394
)
 
1,568
 
 
1,322
 
 
2,890
 
Total cost of natural gas marketing (2)
 
$
 
 
$
(1,843
)
 
$
(1,843
)
 
$
 
 
$
1,066
 
 
$
1,066
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine months ended September 30,
 
 
 
 
 
 
 
 
 
 
 
 
Commodity price risk management gain (loss), net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
19,927
 
 
$
18,410
 
 
$
38,337
 
 
$
62,548
 
 
$
20,197
 
 
$
82,745
 
Unrealized gains (losses)
 
(19,927
)
 
56,098
 
 
36,171
 
 
(62,548
)
 
(33,611
)
 
(96,159
)
Total commodity price risk management gain (loss), net (1)
 
$
 
 
$
74,508
 
 
$
74,508
 
 
$
 
 
$
(13,414
)
 
$
(13,414
)
Sales from natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
2,078
 
 
$
2,392
 
 
$
4,470
 
 
$
4,244
 
 
$
2,472
 
 
$
6,716
 
Unrealized gains (losses)
 
(2,078
)
 
3,266
 
 
1,188
 
 
(4,244
)
 
887
 
 
(3,357
)
Total sales from natural gas marketing (2)
 
$
 
 
$
5,658
 
 
$
5,658
 
 
$
 
 
$
3,359
 
 
$
3,359
 
Cost of natural gas marketing
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains (losses)
 
$
(1,752
)
 
$
(2,402
)
 
$
(4,154
)
 
$
(4,009
)
 
$
(3,000
)
 
$
(7,009
)
Unrealized gains (losses)
 
1,752
 
 
(3,055
)
 
(1,303
)
 
4,009
 
 
(228
)
 
3,781
 
Total cost of natural gas marketing (2)
 
$
 
 
$
(5,457
)
 
$
(5,457
)
 
$
 
 
$
(3,228
)
 
$
(3,228
)
_________
(1)     
Represents realized and unrealized gains and losses on derivative instruments related to natural gas and oil sales.
(2)     
Represents realized and unrealized gains and losses on derivative instruments related to natural gas marketing.
 
Concentration of Credit Risk. A significant component of our future liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and oil. These arrangements expose us to the risk of nonperformance by our counterparties. To date, we have had no counterparty defaults.
 

11

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

With regard to derivative assets, the following table presents the counterparties that expose us to credit risk as of September 30, 2010.
 
 
 
Fair Value of
 
 
Derivative Assets
Counterparty Name
 
September 30, 2010
 
 
(in thousands)
JPMorgan Chase Bank, N.A. (1)
 
$
50,055
 
Credit Agricole CIB (1) (3)
 
32,907
 
Wells Fargo Bank, N.A. (1) (4)
 
18,450
 
Various (2)
 
6,142
 
Total
 
$
107,554
 
__________
(1)     
Major lender in our credit facility. See Note 7.
(2)     
Represents a total of 52 counterparties, including five lenders in our credit facility.
(3)     
Formerly known as Calyon New York Branch.
(4)     
Formerly known as Wachovia Bank, N.A.
 
 
5.    
PROPERTIES AND EQUIPMENT
 
The following table presents the components of properties and equipment, net.
 
 
September 30, 2010
 
 
December 31, 2009
 
(in thousands)
Natural gas and oil properties (successful efforts method of accounting)
 
 
 
 
Proved
$
1,328,824
 
 
 
$
1,281,529
 
Unproved
85,832
 
 
 
38,626
 
Total natural gas and oil properties
1,414,656
 
 
 
1,320,155
 
Pipelines and related facilities
33,898
 
 
 
36,909
 
Transportation and other equipment
31,740
 
 
 
33,432
 
Land and buildings
14,133
 
 
 
14,699
 
Construction in progress
31,535
 
 
 
9,131
 
 
1,525,962
 
 
 
1,414,326
 
Accumulated DD&A
(496,951
)
 
 
(434,953
)
 
 
 
 
 
Properties and equipment, net (1)
$
1,029,011
 
 
 
$
979,373
 
__________
(1)     
As a result of the deconsolidation of and our change in ownership interest in PDCM, properties and equipment were reduced by $67.1 million, net of accumulated depreciation, depletion and amortization ("DD&A") of $20.6 million, from December 31, 2009.   See Notes 2 and 14.
 
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 ordinary 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 ordinary income or tax benefit on ordinary loss at the most recent estimated annual effective tax rate, adjusted for the effect of discrete items.

12

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
The effective tax rate for continuing operations for the nine months ended 2010, was 32.8% (provision on income) compared to a benefit on loss of 38.1% for the nine months ended 2009. The difference in the tax rates is due to the fact that our net permanent deductions, primarily percentage depletion, reduced the tax provision on income in this period, while increasing the tax benefit on our loss for the same prior year period. In addition, a $1.6 million net discrete tax benefit was recorded during the three months ended 2010, resulting in a reduction of our rate for the nine months ended 2010. Our rate for the period excluding discrete items was 36.8%. The net discrete tax benefit was primarily the result of a reduction in our deferred tax rate from 38.4% to 38%. This rate reduction was due to a change in our state deferred rate based upon changes in both projected future state taxing jurisdictions and projected taxable income apportionments to various states. We consistently review and update our estimated deferred tax rate, with an annual adjustment being common in the period when prior year's federal and state tax returns are filed. There were no significant discrete items recorded during the three and nine months ended 2009.
 
As of September 30, 2010, we had a gross liability for uncertain tax benefits of $1 million compared to a liability of $0.6 million as of December 31, 2009. If recognized, $0.9 million of the $1 million liability would affect our effective tax rate. This liability is reflected in federal and state income taxes payable in our accompanying balance sheet. During the three months ended June 30, 2010, the Internal Revenue Service ("IRS") commenced an examination of our 2007, 2008 and 2009 tax years. Therefore, we expect the liability for uncertain tax benefits to decrease significantly during the next twelve-month period as items are either resolved without change, converted to amounts due to the IRS or removed due to the expiration of the statute of limitations.
 
We filed a refund request in May 2010 to reflect our federal 2009 net operating loss ("NOL") carry-back to our 2005 and 2006 tax years. We received our requested federal tax refund of approximately $25.9 million in June 2010. This refund reduced our income tax receivable balance that was recorded at December 31, 2009. Our 2009 NOL is carried forward for state tax purposes and the net benefit of $2.7 million is included as a deferred tax asset and netted against deferred tax liabilities on our balance sheet.
 
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.
 
7.    
LONG-TERM DEBT
 
The following table presents the components of long-term debt.
 
 
 
September 30,
2010
 
 
December 31,
2009
 
 
(in thousands)
12% Senior notes due 2018:
 
 
 
 
 
Principal amount
 
$
203,000
 
 
 
$
203,000
 
Unamortized discount
 
(2,126
)
 
 
(2,343
)
12% Senior notes due 2018, net of discount
 
200,874
 
 
 
200,657
 
Credit facility
 
101,500
 
 
 
80,000
 
Total long-term debt
 
$
302,374
 
 
 
$
280,657
 
 
12% Senior Notes Due 2018
 
In February 2008, we issued 12% senior notes with a total principal amount of $203 million payable at maturity on February 15, 2018. Interest is payable in cash semi-annually in arrears on each February 15th and August 15th. The senior notes were issued at a discount, 98.6% of the principal amount. The original discount and the deferred note issuance costs are being amortized to interest expense over the term of the debt using the effective interest method. As of September 30, 2010, we had $6.2 million in original discount being amortized at a rate of $0.2 million per quarter. We were in compliance with all covenants as of September 30, 2010, and expect to remain in compliance throughout the next year.
 
Credit facility
 
We have a credit facility arranged by JPMorgan Chase Bank, N.A., dated as of November 4, 2005, as amended

13

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

last on December 18, 2009 ("the Eighth Amendment"), with an aggregate revolving commitment of $305 million, which expires on May 22, 2012. The credit facility, through the series of amendments, includes commitments from eleven additional banks. The maximum allowable commitment under the credit facility is $500 million. The credit facility is guaranteed by PDC and its wholly owned subsidiaries, with the exception of certain immaterial subsidiaries, individually and in the aggregate; it is not guaranteed by PDCM. The subsidiary guarantees are full and unconditional and joint and several. The credit facility is subject to and collateralized by our natural gas and oil reserves, exclusive of our proportionate share of PDCM's natural gas and oil reserves. The credit facility requires an aggregated security of a value no less than 80% of the value of the direct interests included in the borrowing base properties. Our credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of reserves at December 31st and June 30th, respectively; additionally, we or our lenders may request a redetermination upon the occurrence of certain events. A commodity price deck reflective of the current and future commodity pricing environment, as determined by our lenders, is utilized to quantify the reserves used in the borrowing base calculation and thus determines the underlying borrowing base.
 
We have an $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider. This letter of credit reduces the amount of available funds under our credit facility by an equal amount. We pay a fronting fee of 0.25% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.5% as of September 30, 2010) for the period the letter of credit remains outstanding. The letter of credit expires on May 22, 2012.
 
As of September 30, 2010, we had $4.2 million in debt issuance costs being amortized at a rate of $0.7 million per quarter; the funds available under our credit facility were $184.8 million; and the interest on our borrowings, inclusive of our standby letter of credit, was accruing at a rate of 3.6% per annum. We were in compliance with all covenants at September 30, 2010, and expect to remain in compliance throughout the next year.
 
See Note 17 regarding the completion of our November 2010 redetermination and the corresponding entry into a second amended and restated credit agreement.
 
PDCM Credit Facility
 
In April 2010, PDCM entered into a credit facility arranged by BNP Paribas ("BNP"), dated as of April 30, 2010, with an initial borrowing base of $10 million. The maximum allowable commitment under the credit facility is $100 million. PDCM is required to pay a commitment fee of 0.5% per annum on the unused portion of the activated credit facility. Based upon PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of BNP's prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.5% to 2.25%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.5% to 3.25%. Debt issuance costs are amortized using the effective interest rate method over the remaining term of the credit facility. As of September 30, 2010, the unamortized debt issuance costs were immaterial. No principal payments are required until the credit agreement expires on April 30, 2014, or in the event that the borrowing base would fall below the outstanding balance. The credit facility is subject to and collateralized by PDCM's natural gas and oil reserves. The credit facility borrowing base is subject to size redeterminations each May and November based upon a quantification of PDCM's reserves at December 31st and June 30th, respectively; 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.
 
The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on PDCM's ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on their assets, (c) consolidate, merge or sell assets, (d) pay dividends and other distributions, (e) make certain investments, loans and advances, (f) enter into sale/leaseback transactions, and (g) engage in hedging activities unless certain requirements are satisfied. The credit facility also requires PDCM to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title. Further, PDCM is required to comply with certain financial tests and maintain certain financial ratios, as defined by the credit facility, on a quarterly basis. The financial tests and ratios include requirements to: (a) maintain a minimum current ratio of 1.0 to 1.0, (b) not to exceed a debt to EBITDAX ratio of 3.5 to 1.0 and (c) maintain a minimum interest coverage ratio of 2.5 to 1.0.
 
As of September 30, 2010, there were no amounts outstanding related to this credit facility. Should borrowings occur, our financial statements would include our proportionate share of the liability, cost and expenses. As of September 30, 2010, PDCM was in compliance with all covenants.

14

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
8.    
ASSET RETIREMENT OBLIGATION
 
The following table presents the changes in carrying amounts of the asset retirement obligation associated with our working interest in natural gas and oil properties.
 
 
Amount
 
(in thousands)
Balance at December 31, 2009 (1)
$
29,564
 
Deconsolidation of PDCM and change in ownership interest
(6,257
)
Obligations incurred with development activities and assumed with acquisitions
3,119
 
Accretion expense
1,043
 
Obligations discharged with disposal of properties and asset retirements
(880
)
Balance at September 30, 2010
26,589
 
Less current portion
(250
)
Long-term portion
$
26,339
 
_________
(1)     
Includes $0.8 million as of December 31, 2009, related to assets held for sale and divested in July 2010. See Note 12.
 
9.    
COMMITMENTS AND CONTINGENCIES
 
Purchase and Sale Agreement
 
See Note 17 regarding our entry into a purchase and sale agreement ("PSA") on October 14, 2010, whereby we expect to acquire producing assets and undeveloped acreage located in the Permian Basin in West Texas for $40 million in cash.
 
Merger Agreements
 
In June 2010, we and a wholly owned subsidiary of ours (the "merger subsidiary") entered into separate merger agreements with each of PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. 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 "investor partners"), as well as the satisfaction of other customary closing conditions, then the applicable partnership will merge with and into the merger subsidiary, with the merger subsidiary being the surviving entity. If all four partnerships are acquired, we will pay an aggregate of approximately $36.5 million for the limited partnership units of the investor partners of these partnerships. Definitive proxy statements for each of the partnerships requesting approval from the applicable investor partners for, among other things, the merger agreements were mailed to the investor partners in early October 2010. The special meetings whereby investor partners will have an opportunity to vote and approve the applicable merger agreement are currently scheduled for December 8, 2010, for each of the partnerships. If the required approvals are received at the special meetings, each of the mergers is expected to close shortly thereafter and no later than December 31, 2010.
 
We intend to borrow the required funds for the aforementioned mergers under our revolving credit facility. There are no material conditions in our ability to obtain the funds and we have not established an alternative financing arrangement. We expect to repay such borrowings with cash from operations in the ordinary course of business.
 
Drilling Rig Contract
 
In order to secure the services of a drilling rig, PDCM entered into a commitment with a drilling contractor for the use of a drilling rig.  As of September 30, 2010, our proportionate share of PDCM's related maximum commitment was $5.1 million. The commitment expires in October 2012.
 
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 other companies, working interest owners and our

15

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

affiliated partnerships. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. Satisfaction of the volume requirements include volumes produced by us and PDCM, volumes purchased from third parties and volumes produced by our affiliated partnerships. As of September 30, 2010, based on a review of our drilling plans and volume projections, we do not expect to meet all future volume requirements for a firm transportation agreement in our Piceance Basin. Accordingly, as of September 30, 2010, we have a related liability in the amount of $3 million, primarily recorded in prior periods, included in other liabilities on the balance sheet. We are currently working with the third party to renegotiate the terms and timing of our volume requirements under this agreement. If we are not able to renegotiate this agreement or meet our expected future volumes, an additional liability may result.
 
The following table presents gross volume information related to our long-term firm sales, processing and transportation agreements for pipeline capacity, including our proportionate share of a commitment related to PDCM. We record in our financial statements only our share of costs incurred based upon our working and net revenue interest in the wells. If the volumes below are not met, we will bear all costs related to the volume shortfall.
 
 
 
 
For the Twelve Months Ending September 30,
 
 
 
 
Area
 
Total
 
2011
 
2012
 
2013
 
2014
 
Thereafter
 
Expiration
Date
Volume (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Piceance
 
200,227
 
 
32,111
 
 
32,699
 
 
31,518
 
 
26,649
 
 
77,250
 
 
May 31, 2021
Appalachian Basin (1)
 
163,856
 
 
3,426
 
 
6,852
 
 
16,510
 
 
16,475
 
 
120,593
 
 
August 31, 2022
NECO
 
13,700
 
 
3,650
 
 
2,285
 
 
1,825
 
 
1,825
 
 
4,115
 
 
December 31, 2016
Total
 
377,783
 
 
39,187
 
 
41,836
 
 
49,853
 
 
44,949
 
 
201,958
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dollar commitment
(in thousands)
 
$
182,640
 
 
$
19,441
 
 
$
20,421
 
 
$
24,604
 
 
$
22,041
 
 
$
96,133
 
 
 
_____________
(1)     
Includes a precedent agreement that becomes effective when the planned pipeline is placed in service, currently estimated to be September 2012 and represents 10,629 MMcf, 10,629 MMcf and 84,215 MMcf of the total MMcf presented for the twelve months ending September 30, 2013, 2014 and thereafter, respectively.  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 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.
 
Royalty Owner Class Action
 
Gobel et al v. Petroleum Development Corporation, Case No. 09-C-40 in U. S. District Court, Northern District of West Virginia, filed on January 27, 2009
 
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 "Gobel lawsuit"). The allegations state that the Company improperly deducted certain charges and costs before applying the royalty percentage. Punitive damages are requested in addition to breach of contract, tort and fraud allegations. On August 31, 2010, the federal judge issued an order remanding the case to state court. On October 27, 2010, the state court set a trial date of April 2012. The Company and the plaintiff have been engaged in settlement discussions. During the three months ended 2010, the Company recorded a charge to natural gas and oil sales in the statement of operations of $3.3 million. As of September 30, 2010, the Company has a total accrual of $6.2 million related to this suit. Given the inherent uncertainty in actions of this nature, the Company is unable to predict the ultimate outcome of this case at this time; however, it could result in a loss in excess of the amount accrued.
 
We are involved in various other legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that the ultimate results of such proceedings will not have a material adverse effect

16

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

on our financial position, results of operations or liquidity.
 
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 assessments and/or clean-ups are probable and the costs can be reasonably estimated. As of September 30, 2010, we have accrued environmental liabilities in the amount of $2 million included in other accrued liabilities on the balance sheet. We are not aware of any environmental claims existing as of September 30, 2010, 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.
 
In July 2008, the Company self-reported to the Colorado Department of Public Health and Environment (the "CDPHE") certain non-compliance with air laws at a compressor station in the Piceance Basin. The CDPHE subsequently initiated a review and inspection of air compliance at this station. In November and December 2009, the Company received related compliance advisories for alleged non-compliance. On May 27, 2010, we entered into a settlement agreement providing for a civil penalty of $163 thousand, which was accrued in periods prior to settlement and paid in the second quarter of 2010.
 
In December 2008, we received a Notice of Violation/Cease and Desist Order (the "Notice") from the CDPHE, related to the stormwater permit for the Garden Gulch Road. The Company manages this private road for Garden Gulch LLC. The Company is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance region of Colorado. Operating expenses, including this fine, if any, are allocated among the users of the road based upon their respective usage. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Company's responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Company entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Company is unable to predict with certainty the ultimate outcome of this administrative action; however, the Company does not believe that the ultimate outcome will have a material adverse effect on the Company's financial position or results of operations.
 
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 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 September 30, 2010, the maximum annual repurchase obligation, based upon the minimum price described above, was approximately $11.6 million. We believe we have adequate liquidity to meet this obligation. For the nine months ended September 30, 2010, 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 Chief Executive Officer, Chief Financial Officer and other executive officers. The employment agreements provide for annual base salaries, eligibility for performance bonus compensation and other various benefits, including retirement and severance benefits.
 
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, the severance benefits equal two times to 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 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 the benefits noted in the preceding sentence. For this purpose, a change of control and good reason correspond to the respective

17

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

definitions of change of control and good reason under Section 409A of the Internal Revenue Code of 1986 (IRC) and the supporting treasury regulations, with some differences. Under any of the above circumstances, the executive officer is also entitled to (i) vesting of any unvested equity compensation (excluding all long-term performance 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 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 401(k) and profit sharing plan, although those benefits are not increased or 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 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 the remaining executive officers, 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 upon presentation by the executive officer of an accounting of such expenses in accordance with our normal practices 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 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 base salary.
 
Partnership Casualty Losses
 
As managing general partner of 33 partnerships, we have liability for potential 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.
 
10.    
STOCK-BASED COMPENSATION PLANS
 
2010 Long-Term Equity Compensation Plan
 
In June 2010, our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, up to 1,400,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of September 30, 2010, 194,596 shares of restricted stock had been awarded pursuant to the 2010 Plan.
 
Other Long-Term Equity Compensation Plans
 
As of September 30, 2010, 2,608 shares remain available for issuance in our 2004 Long-Term Equity Compensation Plan and five shares remain available for issuance in our 2005 Non-Employee Director Restricted Stock Plan. All outstanding and non-vested awards pursuant to these plans will continue to be outstanding and vest pursuant to their original terms.
 
The following table provides a summary of the impact of our stock-based compensation plans on the results of operations for the periods presented.

18

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2010
 
2009
 
2010
 
2009 (1)
 
(in thousands)
Total stock-based compensation expense
$
1,624
 
 
$
918
 
 
$
3,845
 
 
$
4,901
 
Income tax benefit (based on deferred rate)
(617
)
 
(350
)
 
(1,461
)
 
(1,870
)
Net income impact
$
1,007
 
 
$
568
 
 
$
2,384
 
 
$
3,031
 
__________
(1)     
Includes $1.7 million related to agreements with a former chief executive officer and executive vice president.
 
Stock-Based Compensation Awards
 
There have been no material changes in our stock options or market-based restricted stock awards during the nine months ended September 30, 2010.
 
SARs. In April 2010, our Compensation Committee granted SARs to our executive officers. The SARs will vest over a three-year period and may be exercised at any point after vesting through April 2020. 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.
 
 
Nine Months Ended
 
September 30, 2010
Weighted average value per SAR granted during the period:
$13.26
Assumptions:
 
Expected term
5 years
Risk-free interest rate
2.5%
Volatility
62.0%
 
The following table presents the changes in our SARs for the nine months ended September 30, 2010.
 
 
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, 2009
 
 
$
 
 
 
 
$
 
Awarded
57,282
 
 
24.44
 
 
9.6
 
 
 
Outstanding at September 30, 2010
57,282
 
 
24.44
 
 
9.6
 
 
181
 
Vested and expected to vest at September 30, 2010
51,554
 
 
24.44
 
 
9.6
 
 
163
 
Exercisable at September 30, 2010
 
 
 
 
 
 
 
 
The total compensation cost related to SARs granted and not yet recognized in our statement of operations as of September 30, 2010, was $0.6 million. The cost is expected to be recognized over a weighted average period of 2.8 years.
 
Restricted Stock Awards. During the nine months ended September 30, 2010, our Compensation Committee

19

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

granted a total of 151,404 shares of restricted stock to our executive officers and non-employee directors at a weighted average grant date fair value of $23.63 per share and 189,063 shares to our key employees at a weighted average grant date fair value of $25.11 per share. Pursuant to the terms of the awards, the shares will vest over a period of one to four years.
 
The following table presents the changes in our non-vested time-based awards for the nine months ended September 30, 2010.
 
 
Shares
 
Weighted
Average
Grant Date
Fair Value
Non-vested at December 31, 2009
305,328
 
 
$
27.55
 
Granted
340,467
 
 
24.45
 
Vested
(106,624
)
 
28.20
 
Forfeited
(17,778
)
 
29.30
 
Non-vested at September 30, 2010
521,393
 
 
25.33
 
 
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 September 30, 2010, was $10 million. The cost is expected to be recognized over a weighted average period of 2.4 years.
 
11.EARNINGS PER SHARE
 
The following is a reconciliation of the weighted average diluted shares outstanding.
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2010
 
2009
 
2010
 
2009
 
(in thousands)
Weighted average common shares outstanding - basic
19,250
 
 
16,962
 
 
19,218
 
 
15,530
 
Dilutive effect of stock-based compensation:
 
 
 
 
 
 
 
Restricted stock
109
 
 
 
 
80
 
 
 
SARs
39
 
 
 
 
13
 
 
 
Non employee director deferred compensation
8
 
 
 
 
8
 
 
 
Weighted average common shares outstanding - diluted
19,406
 
 
16,962
 
 
19,319
 
 
15,530
 
 
For the three and nine months ended September 30, 2009, the weighted average common shares outstanding for both basic and diluted were the same because the effect of dilutive securities was anti-dilutive due to our net loss attributable to shareholders for the periods. 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.
 

20

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2010
 
2009
 
2010
 
2009
 
(in thousands)
Weighted average common share equivalents excluded from diluted earnings
 
 
 
 
 
 
 
per share due to their anti-dilutive effect:
 
 
 
 
 
 
 
Restricted stock
130
 
 
236
 
 
266
 
 
283
 
Stock options
10
 
 
10
 
 
10
 
 
10
 
Non employee director deferred compensation
 
 
8
 
 
 
 
8
 
Total anti-dilutive common share equivalents
140
 
 
254
 
 
276
 
 
301
 
 
12.    
DIVESTITURE AND DISCONTINUED OPERATIONS
 
Michigan Divestiture. On July 30, 2010, we divested our Michigan asset group and related liabilities for net cash proceeds of $22 million and realized a loss on sale of $4.7 million in the form of an impairment charge recorded during the nine months ended 2010 (see Note 3 regarding the impairment charge). We do not have significant continuing involvement in the operations of or cash flows from this asset group. Accordingly, the results of operations related to the Michigan assets have been separately reported as discontinued operations for all periods presented.
 
Selected financial information related to assets divested and discontinued operations. The tables below set forth selected financial and operational information related to net assets divested, net assets related to discontinued operations and operating results related to discontinued operations. Assets held for sale including related liabilities present the assets that were sold and liabilities that were assumed by the purchaser. Assets and liabilities related to discontinued operations include those assets sold and liabilities assumed by the purchaser as well as all other related assets and liabilities, consisting of accounts receivable and production tax liability, which were not sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the statement of operations and operational tables present the revenues, expenses and production volumes that were reclassified from the specified statement of operations line items to discontinued operations.
 
 
December 31, 2009
Balance Sheet
 
Net Assets Held for Sale (1)
 
Net Assets
Related to Discontinued Operations
 
 
(in thousands)
Assets
 
 
 
 
Current assets
 
 
 
 
Accounts receivable, net
 
$
 
 
$
1,240
 
Total current assets
 
 
 
1,240
 
Properties and equipment, net
 
28,820
 
 
28,820
 
Total assets
 
28,820
 
 
30,060
 
Liabilities
 
 
 
 
Current liabilities
 
 
 
 
Production tax liability
 
 
 
37
 
Total current liabilities
 
 
 
37
 
Asset retirement obligation
 
775
 
 
775
 
Total liabilities
 
775
 
 
812
 
Net assets
 
$
28,045
 
 
$
29,248
 
_____________
(1)     
See Note 8 for additional information regarding the asset retirement obligation related to assets held for sale and divested in July 2010.

21

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
Statement of Operations - Discontinued Operations
 
2010
 
2009
 
2010
 
2009 (1)
 
 
(in thousands)
Revenues
 
 
 
 
 
 
 
 
Natural gas and oil sales
 
$
408
 
 
$
1,135
 
 
$
3,437
 
 
$
3,866
 
Sales from natural gas marketing
 
568
 
 
1,382
 
 
3,328
 
 
4,000
 
Well operations, pipeline income and other
 
120
 
 
299
 
 
491
 
 
651
 
Total revenues
 
1,096
 
 
2,816
 
 
7,256
 
 
8,517
 
 
 
 
 
 
 
 
 
 
Costs, expenses and other
 
 
 
 
 
 
 
 
Natural gas and oil production and well operations costs
 
248
 
 
513
 
 
1,260
 
 
1,381
 
Cost of natural gas marketing
 
537
 
 
1,377
 
 
3,265
 
 
4,005
 
Depreciation, depletion and amortization
 
 
 
641
 
 
1,094
 
 
1,716
 
Impairment of proved natural gas and oil properties
 
160
 
 
 
 
4,666
 
 
 
Total costs, expenses and other
 
945
 
 
2,531
 
 
10,285
 
 
7,102
 
 
 
 
 
 
 
 
 
 
Income (loss) from discontinued operations
 
151
 
 
285
 
 
(3,029
)
 
1,415
 
Provision (benefit) for income taxes
 
(37
)
 
106
 
 
(1,300
)
 
562
 
Income (loss) from discontinued operations, net of tax
 
$
188
 
 
$
179
 
 
$
(1,729
)
 
$
853
 
 
 
 
 
 
 
 
 
 
Operational Data
 
 
 
 
 
 
 
 
Production
 
 
 
 
 
 
 
 
   Natural gas (Mcf)
 
54,694
 
 
390,320
 
 
755,606
 
 
1,042,256
 
   Oil (Bbls)
 
38
 
 
697
 
 
2,137
 
 
2,275
 
   Natural gas equivalent (Mcfe)
 
54,922
 
 
394,502
 
 
768,428
 
 
1,055,906
 
_____________
(1)    Represents only the impact of the divestiture of our Michigan assets; excludes revenues of $193 thousand ($113 thousand, net of tax) related to our natural gas and oil well drilling segment, which was reported as discontinued operations in March 2009.
 
13.    ACQUISITION
 
On July 30, 2010, we acquired various producing assets located in the Wolfberry oil trend in the Permian Basin in West Texas. In conjunction with the divestiture of our Michigan asset group we entered into a like-kind exchange agreement, in accordance with Internal Revenue Code Section 1031 ("IRC 1031"), with a qualified intermediary. The Wolfberry assets were identified as our replacement property in accordance with IRC 1031. Sales proceeds in the amount of $19.3 million from the Michigan divestiture were transferred directly to the qualified intermediary and used, along with $55.7 million from our credit facility, to fund our Wolfberry acquisition. The sale of our Michigan assets resulted in a gain for income tax purposes of $19.2 million, which then resulted in a tax liability of $7.3 million. With the favorable deferral aspects of IRC 1031, we were able to defer $6.5 million of this tax liability.
 
The following table presents the adjusted purchase price and preliminary allocation thereof based on estimates of fair value.
 

22

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
 
Amount
 
 
(in thousands)
Cash consideration paid to seller
 
$
74,996
 
Payable to seller
 
590
 
Total consideration for net assets
 
$
75,586
 
 
 
 
Recognized amounts of identifiable assets acquired and liabilities assumed:
 
 
Proved natural gas and oil properties
 
$
29,187
 
Unproved natural gas and oil properties
 
48,657
 
Asset retirement obligation
 
(1,272
)
Environmental liability
 
(986
)
Total identifiable net assets
 
$
75,586
 
 
Pro Forma Information. The results of operations for our Permian acquisition have been included in our consolidated financial statements from the date of acquisition. The pro forma effect of the inclusion in our consolidated statement of operations of the results of operations of these assets as if the acquisition had occurred at the beginning of the periods presented, is not presented as it would not be materially different from the information presented in the accompanying interim statement of operations.
 
14.    NONCONTROLLING INTEREST
 
The following table presents the changes in noncontrolling interest.
 
 
Amount
 
(in thousands)
Balance at December 31, 2009
$
47,678
 
Deconsolidation of PDCM
(47,322
)
Net loss attributable to noncontrolling interest
(66
)
Balance at September 30, 2010
$
290
 
 
PDCM
 
In October 2009, we entered into a joint venture arrangement to form PDCM. At that time, the joint venture was determined to be a variable interest entity due to the disproportionate voting rights compared to our ownership interest; accordingly, we consolidated 100% of the joint venture as we were the primary beneficiary as of and for the period ended December 31, 2009. As of January 1, 2010, pursuant to the adoption of new accounting changes related to variable interest entities (see Note 2), the joint venture was deconsolidated from 100% and proportionately consolidated at 67.4%, representing only our ownership interest. Further, on April 1, 2010, our joint venture partner made a cash capital contribution to PDCM of $28 million, resulting in a change in our ownership interest in PDCM of approximately 9.6%, decreasing from 67.4% to 57.8%, which continues to represent our interest ownership as of September 30, 2010.
 
The following table presents the impact on our balance sheet resulting from the deconsolidation of PDCM on January 1 and our change in ownership interest on April 1. The changes below are non-cash items with the exception of the changes in cash and cash equivalents, which are reflected in the statement of cash flows.
 

23

PETROLEUM DEVELOPMENT CORPORATION
(dba PDC Energy)

 
Decreased/(Increased)
 
 
Decreased/(Increased)
 
January 1, 2010
 
April 1, 2010
 
 
January 1, 2010
 
April 1, 2010
 
(in thousands)
 
 
(in thousands)
Assets
 
 
 
 
Liabilities and Equity
 
 
 
Current assets
 
 
 
 
Current liabilities
 
 
 
Cash and and cash equivalents
$
3,074
 
 
$
398
 
 
Accounts payable
$
813
 
 
$
426
 
Accounts receivable, net
1,335
 
 
335