form10q.htm


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

FORM 10-Q


S Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2009

OR

£ 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

 
Logo
PETROLEUM DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)
   
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 S     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 £     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  S
Accelerated filer  £
Non-accelerated filer  £
Smaller reporting company  £
   
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes £     No S

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 14,876,769 shares of the Company's Common Stock ($.01 par value) were outstanding as of April 30, 2009.
 



 
 

 

PETROLEUM DEVELOPMENT CORPORATION

INDEX


   
     
Item 1.
 
 
2
 
3
 
4
 
5
Item 2.
23
Item 3.
35
Item 4.
38
     
     
     
   
     
Item 1.
38
Item 1A.
38
Item 2.
39
Item 3.
39
Item 4.
39
Item 5.
39
Item 6.
40
     
     
 
41

 
1

 
Index
 
PART I - FINANCIAL INFORMATION

Item 1.  Financial Statements (unaudited)

Petroleum Development Corporation
 Condensed Consolidated Balance Sheets
(in thousands, except share data)


   
March 31,
   
December 31,
 
   
2009
    2008*  
Assets
             
Current assets:
             
Cash and cash equivalents
  $ 41,132     $ 50,950  
Restricted cash - current
    19,009       19,030  
Accounts receivable, net
    61,375       69,688  
Accounts receivable - affiliates
    15,272       16,742  
Inventory
    1,052       4,310  
Fair value of derivatives - current
    139,367       116,881  
Prepaid expenses and other current assets
    9,229       14,836  
Total current assets
    286,436       292,437  
Properties and equipment, net
    1,046,215       1,033,078  
Fair value of derivatives - non current
    28,241       47,155  
Other assets
    38,874       30,034  
Total Assets
  $ 1,399,766     $ 1,402,704  
                 
Liabilities and Equity
               
Liabilities
               
Current liabilities:
               
Accounts payable
  $ 61,117     $ 90,532  
Accounts payable - affiliates
    45,617       40,540  
Production tax liability
    17,830       18,226  
Federal and state income taxes payable
    1,661       1,591  
Fair value of derivatives - current
    5,648       4,766  
Funds held for future distribution
    38,869       50,361  
Net deferred income taxes - current
    29,261       28,355  
Other accrued expenses
    18,713       26,800  
Total current liabilities
    218,716       261,171  
Long-term debt
    422,939       394,867  
Net deferred income taxes - non current
    154,999       162,593  
Asset retirement obligation
    23,912       23,036  
Fair value of derivatives - non current
    31,863       5,720  
Other liabilities
    39,542       43,042  
Total liabilities
    891,971       890,429  
                 
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:  14,881,886 in 2009 and 14,871,870 in 2008
    149       149  
Additional paid-in capital
    7,063       5,818  
Retained earnings
    500,203       505,906  
Treasury shares, at cost; 7,291 shares in 2009 and 7,066 in 2008
    (298 )     (292 )
Total shareholders' equity
    507,117       511,581  
Noncontrolling interest in WWWV, LLC
    678       694  
Total equity
    507,795       512,275  
Total Liabilities and Equity
  $ 1,399,766     $ 1,402,704  
 
_______________
*Derived from audited 2008 balance sheet.


See accompanying notes to condensed consolidated financial statements.

 
2

 
Index
 
Petroleum Development Corporation
Condensed Consolidated Statements of Operations
(unaudited; in thousands, except per share data)


   
Three Months Ended March 31,
 
   
2009
   
2008
 
             
Revenues:
           
Oil and gas sales
  $ 39,742     $ 71,646  
Sales from natural gas marketing activities
    22,389       23,325  
Well operations and pipeline income
    2,796       2,352  
Oil and gas well drilling
    193       3,083  
Oil and gas price risk management gain (loss), net
    23,683       (42,310 )
Other
    42       3  
Total revenues
    88,845       58,099  
                 
Costs and expenses:
               
Oil and gas production and well operations cost
    16,216       18,132  
Cost of natural gas marketing activities
    21,878       22,121  
Cost of oil and gas well drilling
    145       78  
Exploration expense
    5,643       4,283  
General and administrative expense
    12,094       9,823  
Depreciation, depletion and amortization
    34,344       21,131  
Total costs and expenses
    90,320       75,568  
                 
Gain on sale of leaseholds
    120       -  
                 
Loss from operations
    (1,355 )     (17,469 )
Interest income
    20       271  
Interest expense
    (8,383 )     (4,932 )
                 
Loss before income taxes
    (9,718 )     (22,130 )
Benefit for income taxes
    (4,015 )     (8,202 )
Net loss
  $ (5,703 )   $ (13,928 )
                 
Loss per share
               
Basic
  $ (0.39 )   $ (0.95 )
Diluted
  $ (0.39 )   $ (0.95 )
Weighted average common shares outstanding
               
Basic
    14,793       14,738  
Diluted
    14,793       14,738  


See accompanying notes to condensed consolidated financial statements.

 
3

 
Index

Petroleum Development Corporation
Condensed Consolidated Statements of Cash Flows
(unaudited, in thousands)


   
Three Months Ended March 31,
 
   
2009
   
2008
 
             
Cash flows from operating activities:
           
Net loss
  $ (5,703 )   $ (13,928 )
Adjustments to net loss to reconcile to cash provided by operating activities:
               
Deferred income taxes
    (6,688 )     (9,738 )
Depreciation, depletion and amortization
    34,344       21,131  
Exploratory dry hole costs
    832       1,100  
Amortization and impairment of unproved properties
    614       442  
Unrealized loss on derivative transactions
    13,188       39,334  
Other
    3,154       2,047  
Changes in assets and liabilities
    (3,862 )     8,401  
Net cash provided by operating activities
    35,879       48,789  
                 
Cash flows from investing activities:
               
Capital expenditures
    (73,697 )     (64,321 )
Other
    120       204  
Net cash used in investing activities
    (73,577 )     (64,117 )
                 
Cash flows from financing activities:
               
Proceeds from credit facility
    100,500       42,000  
Repayment of credit facility
    (72,500 )     (277,000 )
Proceeds from senior notes
    -       200,101  
Payment of debt costs
    (45 )     (4,486 )
Proceeds from exercise of stock options
    -       367  
Excess tax benefits from stock based compensation
    -       154  
Purchase of treasury stock
    (75 )     (4,357 )
Net cash provided by (used in) financing activities
    27,880       (43,221 )
                 
Net decrease in cash and cash equivalents
    (9,818 )     (58,549 )
Cash and cash equivalents, beginning of period
    50,950       84,751  
Cash and cash equivalents, end of period
  $ 41,132     $ 26,202  
                 
Supplemental cash flow information:
               
Cash payments for:
               
Interest, net of capitalized interest
  $ 15,215     $ 2,108  
Income taxes, net of refunds
    (2,364 )     (6,335 )
Non-cash investing activities:
               
Change in accounts payable related to purchases of properties and equipment
    (24,323 )     (11,383 )
Change in asset retirement obligation, with a corresponding increase to oil and gas properties, net of disposals
    541       133  
Change in accounts payable related to debt costs
    -       306  


See accompanying notes to condensed consolidated financial statements.

 
4

 
Index
 
Petroleum Development Corporation
Notes to Condensed Consolidated Financial Statements
March 31, 2009
(unaudited)

1.     GENERAL

Petroleum Development Corporation ("PDC"), together with our consolidated entities (the "Company"), is an independent energy company engaged primarily in the exploration, development, production and marketing of oil and natural gas.  Since we began oil and natural gas operations in 1969, we have grown primarily through exploration and development activities, the acquisition of producing oil and natural gas wells and the expansion of our natural gas marketing activities.

The accompanying condensed consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries and WWWV, LLC, an entity in which we have a controlling financial interest.  All material intercompany accounts and transactions have been eliminated in consolidation.  We account for our investment in interests in oil and natural gas 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 the limited partnerships in which we participate.  Our proportionate share of all significant transactions between us and the limited partnerships has been eliminated.

The accompanying condensed consolidated financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission ("SEC").  Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted.  In our opinion, the accompanying condensed consolidated financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly our financial position, results of operations and cash flows for the periods presented.  The results of operations for the three months ended March 31, 2009, 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.

The accompanying condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the SEC on February 27, 2009 ("2008 Form 10-K").

2.     RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“FAS”) No. 141 (revised 2007), Business Combinations (“FAS No. 141(R)”).  FAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  FAS No. 141(R) also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.  Additionally, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred.  The provisions of FAS No. 141(R) became effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of FAS No. 141(R) became effective as of that date for all acquisitions, regardless of the acquisition date.  FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.  FAS No. 141(R) further amends FAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.  In April 2009, the FASB issued FASB Staff Position (“FSP”) No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP 141(R)-1”), amending the guidance of FAS No. 141(R) to required that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance with FAS No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss.  Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value.  We adopted the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009, for which the provisions will be applied prospectively in our accounting for future acquisitions, if any.  Upon adoption, we recorded a charge of $1.5 million to general and administrative expense related to deferred acquisition costs.

 
5

 
Index

In December 2007, the FASB issued FAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  FAS No. 160 states that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity.  Additionally, FAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  We adopted the provisions of FAS No. 160 effective January 1, 2009.  Upon adoption of FAS No. 160, we reclassified our noncontrolling interest in WWWV, LLC from the mezzanine section, between liabilities and equity, of the consolidated balance sheets, to a component of equity, separate from our shareholders’ equity.  Net loss attributable to noncontrolling interest for the three months ended March 31, 2009 and 2008, is immaterial and is recorded in depreciation, depletion and amortization in the accompanying condensed consolidated statements of operations.

In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157 (“FAS No. 157”) (“FSP 157-2”), which delayed the effective date of FAS No. 157, Fair Value Measurements, by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Effective January 1, 2009, we adopted the provisions of FAS No. 157 delayed by FSP 157-2.  The adoption of FSP 157-2 did not have a material impact on our accompanying condensed consolidated financial statements.  See Note 3, Fair Value Measurements.

In March 2008, the FASB issued FAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  We adopted the provisions of FAS No. 161 effective January 1, 2009.  The adoption of FAS No. 161 did not have a material impact on our accompanying condensed consolidated financial statements.  See Note 4, Derivative Financial Instruments.

Recently Issued Accounting Standards

On April 9, 2009, the FASB issued the following amendments to the fair value measurement and disclosure standards:

 
·
FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP 157-4”)

 
·
FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP 107-1/APB 28-1”)

FSP 157-4 affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction; clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active; eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise and instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence; requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable; and applies to all fair value measurements when appropriate.

FSP 107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of Financial Instruments, to require an entity to provide disclosures about fair value of financial instruments in interim financial information.  This FSP also amends Accounting Principles Board (“APB”) Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.  Pursuant to this FSP, a reporting entity shall include disclosures about the fair value of our financial instruments whenever it issues summarized financial information for interim reporting periods.  In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by FAS No. 107.

Both FSP 157-4 and FSP 107-1/APB 28-1 are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  However, early adoption is allowed only if certain FSPs are early adopted together: an entity early adopting FSP 157-4 must also early adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (“FSP 115-2/124-2”) and an entity early adopting FSP 107-1/APB 28-1 must also elect to early adopt FSP 157-4 and FSP 115-2/124-4.  We do not expect these FSPs to have a significant impact on our consolidated financial statements when adopted on April 1, 2009.

 
6

 
Index

In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting, which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves.  The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period.  The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules.  The revised reporting and disclosure requirements are effective for our Form 10-K for the year ended December 31, 2009.  Early adoption is not permitted.  We are evaluating the impact that adoption of this final rule will have on our consolidated financial statements, related disclosure and management’s discussion and analysis.

3.     FAIR VALUE MEASUREMENTS

Determination of Fair Value.  We determine the fair value of our assets and liabilities, unless specifically excluded, pursuant to FAS No. 157.  FAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

FAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.  The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Included in Level 1 are our commodity derivative instruments for New York Mercantile Exchange (“NYMEX”)-based natural gas swaps.

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.  Included in Level 3 are our asset retirement obligations and our commodity derivative instruments for Colorado Interstate Gas (“CIG”) and Panhandle Eastern Pipeline (“PEPL”)-based natural gas swaps, oil swaps, oil and natural gas options, and physical sales and purchases and our natural gas basis protection derivative instruments.

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 our nonperformance risk on our own liabilities as well as the credit standing of our counterparties.  We primarily use three financial institutions as counterparties to our derivative contracts, with two of them holding the majority of our derivative assets.  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, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.  As of March 31, 2009, no valuation allowance was recorded.  Furthermore, 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.

 
7

 
Index
 
The following table presents, by hierarchy level, our derivative financial instruments, including both current and non-current portions, measured at fair value as of December 31, 2008, and March 31, 2009:


   
Level 1
   
Level 3
   
Total
 
   
(in thousands)
 
As of December 31, 2008
                 
Assets:
                 
Commodity based derivatives
  $ 19,359     $ 144,644     $ 164,003  
Basis protection derivative contracts
    -       33       33  
Total assets
    19,359       144,677       164,036  
Liabilities:
                       
Commodity based derivatives
    (658 )     (5,490 )     (6,148 )
Basis protection derivative contracts
    -       (4,338 )     (4,338 )
Total liabilities
    (658 )     (9,828 )     (10,486 )
Net assets
  $ 18,701     $ 134,849     $ 153,550  
As of March 31, 2009
                       
Assets:
                       
Commodity based derivatives
  $ 21,371     $ 146,102     $ 167,473  
Basis protection derivative contracts
    -       135       135  
Total assets
    21,371       146,237       167,608  
Liabilities:
                       
Commodity based derivatives
    (2,671 )     (6,499 )     (9,170 )
Basis protection derivative contracts
    -       (28,341 )     (28,341 )
Total liabilities
    (2,671 )     (34,840 )     (37,511 )
Net assets
  $ 18,700     $ 111,397     $ 130,097  


The following table presents the changes in our Level 3 derivative financial instruments measured on a recurring basis:

   
(in thousands)
 
       
Fair value, net asset, as of December 31, 2008
  $ 134,849  
Unrealized gains (losses) included in statement of operations line item:
       
Oil and gas price risk management gain, net
    13,245  
Sales from natural gas marketing activities
    291  
Cost of natural gas marketing activities
    (2,684 )
Change in fair value included in balance sheet line item: (1)
       
Accounts receivable - affiliates
    (8,247 )
Accounts payable - affiliates
    (1,192 )
Purchases
       
Oil and gas price risk management gain, net
    (78 )
Sales from natural gas marketing activities
    68  
Cost of natural gas marketing activities
    (13 )
Settlements
       
Oil and gas price risk management gain, net
    (26,403 )
Sales from natural gas marketing activities
    (194 )
Cost of natural gas marketing activities
    1,755  
Fair value, net asset, as of March 31, 2009
  $ 111,397  
         
Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2009, included in statement of operations line item:
       
Oil and gas price risk management gain, net
  $ 13,245  
Sales from natural gas marketing activities
    291  
Cost of natural gas marketing activities
    (2,684 )
    $ 10,852  
____________________        
(1) Represents the change in fair value related to derivative instruments entered into by us and allocated to our affiliated partnerships.

See Note 4, Derivative Financial Instruments, for additional disclosure related to our derivative financial instruments.
 
Non-Derivative Assets and Liabilities.  The carrying values of the financial instruments comprising cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.

 
8

 
Index

In accordance with FAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we assess our oil and gas 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 oil and natural gas.  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 oil and gas 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.  No impairment of oil and gas properties was recognized during the three months ended March 31, 2009.

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 estimate the fair value of the portion of our long-term debt related to our senior notes to be approximately $133.7 million or approximately 65.9% of par value as of March 31, 2009.  We determined this valuation based upon measurements of trading activity and quotes provided by brokers and traders participating in the trading of the securities.

We account for asset retirement obligations by recording the estimated fair value of our plugging and abandonment obligations when incurred, which is when the well is completely drilled.  We estimate the fair value of our plugging and abandonment obligations based on a discounted cash flows analysis.  Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the liabilities are accreted for the change in their present value, through charges to oil and gas production and well operations costs.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  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.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.  See Note 7, Asset Retirement Obligations, for a reconciliation of changes in our asset retirement obligation for the three months ended March 31, 2009.

4.     DERIVATIVE FINANCIAL INSTRUMENTS

We are exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to our oil and natural gas sales and natural gas marketing segments.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities.  We employ established policies and procedures to manage the risks associated with these market fluctuations using commodity derivative instruments.  Our policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

We account for derivative financial instruments in accordance with FAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  As of March 31, 2009, and December 31, 2008, none of our derivative instruments qualified for use of hedge accounting under the terms of FAS No. 133.  Accordingly, we recognize all derivative instruments as either assets or liabilities on our accompanying condensed consolidated balance sheets at fair value, and changes in the fair value of those derivative instruments allocated to us are recorded in our accompanying condensed consolidated statements of operations and changes in the fair value of those derivative instruments allocated to the affiliated partnerships are recorded in accounts payable and accounts receivable – affiliates in our accompanying condensed consolidated balance sheets.  Changes in the fair value of derivative instruments allocated to us and related to our oil and gas sales activities are recorded in oil and gas price risk management, net and changes in fair value of derivatives related to our natural gas marketing activities are recorded in sales from and cost of natural gas marketing activities.

Included in the fair value of our derivative assets and liabilities on our accompanying condensed consolidated balance sheets are the portion of derivative instruments entered into by us and allocated to our affiliated partnerships, as well as a corresponding offsetting payable to and receivable from the partnerships, respectively.  The affiliated partnerships bear their allocated share of counterparty risk and therefore are responsible for their allocated share of derivative losses.  As positions allocated to our affiliated partnerships settle, the realized gains and losses are netted.  Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ oil and gas revenues.

Validation of a contract’s 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.  See Note 3, Fair Value Measurements, for a discussion of how we fair value our derivative instruments.

As of March 31, 2009, we had hedges in place for a portion of our anticipated production through 2012 for a total of 37,095,133 Mmbtu of natural gas and 1,000,721 Bbls of crude oil.

Economic Hedging Strategies.  Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas.  To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative contracts.  As of March 31, 2009, our derivative instruments were comprised of natural gas collars and swaps, oil swaps and basis protection swaps and collars.

 
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·
For swap instruments, if the market price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the market price and the fixed contract price to the counterparty.

 
·
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point.  For CIG basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

 
·
Collars contain a fixed floor price (put) and ceiling price (call).  If the market price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and market price from the counterparty.  If the market price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and market price to the counterparty.  If the market price is between the put and call strike price, no payments are due to or from the counterparty.

For our oil and gas sales activities, we set collars and swaps for our own and affiliated partnerships’ production to protect against price declines in future periods.  For our natural gas marketing activities, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts.  In order to offset these fixed-price physical derivatives, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative.  While these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.  We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended.

Our derivative instruments are recorded at fair value in accordance with FAS No. 157.  The following table summarizes the location and fair value amounts of our derivative instruments in the accompanying condensed consolidated balance sheets as of March 31, 2009, and December 31, 2008.

       
Fair Value
 
Derivatives not qualifying for hedge accounting under FAS No. 133 (1):
 
Balance sheet line item
 
March 31, 2009
   
December 31, 2008
 
         
(in thousands)
 
Derivative Assets:
Current
               
 
Commodity contracts
               
 
Related to oil and gas sales activities
 
Fair value of derivatives
  $ 134,081     $ 112,036  
 
Related to natural gas marketing activities
 
Fair value of derivatives
    5,156       4,820  
 
Basis protection contracts
                   
 
Related to natural gas marketing activities
 
Fair value of derivatives
    130       25  
 
Non Current
                   
 
Commodity contracts
                   
 
Related to oil and gas sales activities
 
Fair value of derivatives
    26,682       45,971  
 
Related to natural gas marketing activities
 
Fair value of derivatives
    1,554       1,176  
 
Basis protection contracts
                   
 
Related to natural gas marketing activities
 
Fair value of derivatives
    5       8  
Total Derivative Assets
      $ 167,608     $ 164,036  
                       
Derivative Liabilities:
Current
                   
 
Commodity contracts
                   
 
Related to natural gas marketing activities
 
Fair value of derivatives
  $ (5,576 )   $ (4,720 )
 
Basis protection contracts
                   
 
Related to natural gas marketing activities
 
Fair value of derivatives
    (72 )     (46 )
 
Non Current
                   
 
Commodity contracts
                   
 
Related to oil and gas sales activities
 
Fair value of derivatives
    (1,986 )     -  
 
Related to natural gas marketing activities
 
Fair value of derivatives
    (1,608 )     (1,428 )
 
Basis protection contracts
                   
 
Related to oil and gas sales activities
 
Fair value of derivatives
    (28,269 )     (4,292 )
Total Derivative Liabilities
      $ (37,511 )   $ (10,486 )
____________________
(1) As of March 31, 2009, and December 31, 2008, none of our derivative instruments qualified for hedge accounting under FAS No. 133.
 
In addition to including the gross assets and liabilities related to our share of oil and gas production, the above table and our accompanying condensed consolidated balance sheets include the gross assets and liabilities related to derivative contracts we entered
 
 
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 into and those that we allocate to our affiliated partnerships as the managing general partner.  For those derivative contracts which we have allocated to the affiliated partnerships, we have on our accompanying condensed consolidated balance sheets a corresponding payable to and receivable from the partnerships of $36.2 million and $10.6 million, respectively, as of March 31, 2009, and $37.5 million and $1.6 million, respectively, as of December 31, 2008.

The following table summarizes the location and amounts of gains and losses on derivative instruments that do not qualify for hedge accounting under FAS No. 133 in our accompanying condensed consolidated statements of operations for the three months ended March 31, 2009 and 2008.

 
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Three Months Ended March 31,
 
   
2009
   
2008
 
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)
 
                                     
Oil and gas price risk management gain (loss), net (1)
                                   
Realized gains (losses)
  $ 30,193     $ 6,433     $ 36,626     $ (351 )   $ (2,060 )   $ (2,411 )
Unrealized gains (losses)
    (30,193 )     17,250       (12,943 )     351       (40,250 )     (39,899 )
Total oil and gas price risk management gain (loss), net (1)
  $ -     $ 23,683     $ 23,683     $ -     $ (42,310 )   $ (42,310 )
Sales from natural gas marketing activities(2)
                                               
Realized gains (losses)
  $ 2,109     $ 259     $ 2,368       989       (503 )   $ 486  
Unrealized gains (losses)
    (2,109 )     2,934       825       (989 )     (6,649 )     (7,638 )
Total sales from natural gas marketing activities(2)
  $ -     $ 3,193     $ 3,193     $ -     $ (7,152 )   $ (7,152 )
Cost of natural gas marketing activities(2)
                                               
Realized gains (losses)
  $ (1,970 )   $ 1,663     $ (307 )     (672 )     738     $ 66  
Unrealized gains (losses)
    1,970       (3,040 )     (1,070 )     672       7,531       8,203  
Total cost of natural gas marketing activities(2)
  $ -     $ (1,377 )   $ (1,377 )   $ -     $ 8,269     $ 8,269  

__________
   (1) Represents realized and unrealized gains and losses on derivative instruments related to our oil and gas sales activities.
   (2) Includes realized and unrealized gains and losses on derivative instruments related to our natural gas marketing activities.

Concentration of Credit Risk.  A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing oil and natural gas.  These arrangements expose us to credit risk of nonperformance by our counterparties.  These contracts consist of fixed price swaps, basis swaps and collars.  We primarily use three financial institutions, who 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, we have determined that the impact of the nonperformance of our counterparties on the fair value of our derivative instruments is insignificant.   As of March 31, 2009, no valuation allowance was recorded.

As of March 31, 2009, the following counterparties expose us to credit risk.
   
Fair Value of
 
   
Derivative Assets
 
Counterparty Name
 
March 31, 2009
 
   
(in thousands)
 
       
JPMorgan Chase Bank, N.A. (1)
  $ 89,960  
BNP  Paribas (1)
    75,604  
Various (2)
    2,044  
         
Total
  $ 167,608  
__________
(1)           Major lender in our credit facility, see Note 6.
(2)           Represents a total of 48 counterparties, includes two lenders in our credit facility.

 
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5.     PROPERTIES AND EQUIPMENT

   
March 31, 2009
   
December 31, 2008
 
   
(in thousands)
 
Properties and equipment, net:
           
Oil and gas properties (successful efforts method of accounting)
           
Proved
  $ 1,291,704     $ 1,245,316  
Unproved
    32,562       32,768  
Total oil and gas properties
    1,324,266       1,278,084  
Pipelines and related facilities
    34,776       34,067  
Transportation and other equipment
    32,198       31,693  
Land and buildings
    14,270       14,570  
Construction in progress
    565       275  
      1,406,075       1,358,689  
Accumulated depreciation, depletion and amortization ("DD&A")
    (359,860 )     (325,611 )
                 
    $ 1,046,215     $ 1,033,078  

Suspended Well Costs.

The following table identifies the capitalized exploratory well costs that are pending determination of proved reserves and are included in properties and equipment in the our accompanying condensed consolidated balance sheets.

         
Number
 
   
Amount
   
of Wells
 
   
(in thousands)
       
             
Beginning balance at December 31, 2008
  $ 1,180       6  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    5,167       4  
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
    (3,256 )     (2 )
Capitalized exploratory well costs charged to expense
    (318 )     (2 )
Ending balance at March 31, 2009
  $ 2,773       6  

As of March 31, 2009, none of the six suspended wells awaiting the determination of proved reserves have been capitalized for a period greater than one year after the completion of drilling.

6.     LONG-TERM DEBT

Long-term debt consists of the following:

   
March 31, 2009
   
December 31, 2008
 
   
(in thousands)
 
             
Credit facility
  $ 222,500     $ 194,500  
12% Senior notes due 2018, net of discount of $2.6 million
    200,439       200,367  
Total long-term debt
  $ 422,939     $ 394,867  

 
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Credit facility

We have a credit facility co-arranged by JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, as amended last on November 12, 2008, dated as of November 4, 2005, with an available commitment of $375 million as of March 31, 2009.  The credit facility, through a series of amendments, includes commitments from: Wachovia Bank N.A.; Bank of America, N.A.; Bank of Oklahoma; Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; The Royal Bank of Scotland, plc; Calyon New York Branch; Compass Bank; The Bank of Nova Scotia; and BMO Capital Markets Financing, Inc.  The maximum allowable commitment under the current credit facility is $400 million.  The credit facility is subject to and secured by required levels of oil and natural gas 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 April and October based upon a quantification of our reserves at December 31st and June 30th, respectively; additionally, 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 agreed upon by us and our lenders, is utilized to quantify our reserve reports and determine the underlying borrowing base.

We are required to pay a commitment fee of .5% per annum on the unused portion of the activated credit facility.  Interest accrues at an alternative base rate ("ABR") or adjusted LIBOR at our discretion.  The ABR is the greater of JPMorgan's prime rate, an adjusted secondary market rate for a three-month certificate of deposit plus 1% or the federal funds effective rate plus .5%.  ABR borrowings are assessed an additional margin spread up to 1.375% and adjusted LIBOR borrowings are assessed an additional margin spread of 1.625% to 2.375% based upon the outstanding balance as a percentage of the available balance.  The credit agreement requires, among other things, the maintenance of certain working capital and tangible net worth ratios.  No principal payments are required until the credit agreement expires on November 4, 2010.

The credit facility contains covenants customary for agreements of this type, including, but not limited to, limitations on our ability to: (a) incur additional indebtedness and guarantees, (b) create liens and other encumbrances on our 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 us to execute and deliver specified mortgages and other evidences of security and to deliver specified opinions of counsel and other evidences of title.  In addition, we are required to comply with certain financial tests and maintain certain financial ratios. The financial tests and ratios include requirements to: (a) maintain a minimum ratio of consolidated current assets to consolidated current liabilities, or working capital ratio, as defined, and (b) not to exceed a maximum leverage ratio.

In April 2009, we commenced the biannual redetermination of our borrowing base, which will be sized based upon a quantification of our oil and natural gas reserves as of December 31, 2008.  Additionally, we have requested an extension and renewal of the credit facility for a three year term and have requested certain adjustments to the terms and conditions of the facility.  We expect to have an increase in the borrowing rate under the facility.  We expect to complete the facility renewal and extension in the second quarter of 2009.  There is no assurance that we will successfully renew our credit facility as expected, if at all, or that all of the current lenders in our credit facility will participate in the renewal; further, there is no assurance that our borrowing base will not be reduced from its current level as a result of the renewal.
 
As of March 31, 2009, we had drawn $222.5 million from our credit facility compared to $194.5 million as of December 31, 2008.  The borrowing rate on the outstanding balance was 4.5% as of March 31, 2009, compared to 4.6% as of December 31, 2008.  Amounts outstanding under our credit facility are secured by substantially all of our properties.  We were in compliance with all covenants at March 31, 2009, and expect to remain in compliance throughout the next year.
 
12% Senior Notes Due 2018

Our outstanding 12% senior notes were issued on February 8, 2008.  The principal amount of the senior notes is $203 million, which is payable at maturity on February 15, 2018.  Interest is payable in cash semi-annually in arrears on each February 15 and August 15.  The senior notes were issued at a price of 98.572% of the principal amount.  In addition, $5.4 million in costs associated with the issuance of the debt has been capitalized as a deferred loan cost.  The original discount and the deferred loan costs are being amortized to interest expense over the term of the debt using the effective interest method.

 
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The indenture governing the notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) pay dividends or other payments by restricted subsidiaries, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company.  Additionally, we are subject to two incurrence covenants: 1) earnings before interest, taxes, depreciation, amortization and capital expenditures (“EBITDAX”) of at least two times interest expense and 2) total debt of less than 4.0 times EBITDAX.  We were in compliance with all covenants as of March 31, 2009, and expect to remain in compliance throughout the next year.

The notes are senior unsecured obligations and rank, in right of payment, equally with all of our existing and future senior unsecured indebtedness and senior to any of our existing and future subordinated indebtedness.  The notes are effectively subordinated to any of our existing or future secured indebtedness to the extent of the assets securing such indebtedness.

The notes are not initially guaranteed by any of our subsidiaries.  However, subsidiaries may be obligated to guarantee the notes if:

 
• 
a subsidiary is a guarantor under our senior credit facility; and
 
• 
the subsidiary has consolidated tangible assets that constitute 10% or more of our consolidated tangible assets.

Subject to specified exceptions, any subsidiary guarantor will be restricted from entering into certain transactions including the disposition of all or substantially all of its assets or merging with or into another entity.  Subsidiary guarantors may be released from a guarantee under circumstances specified in the indenture.  As of March 31, 2009, none of our subsidiaries were obligated as guarantors of our senior notes.

The indenture provides that at any time, which may be more than once, before February 15, 2011, we may redeem up to 35% of the outstanding notes with proceeds from one or more equity offerings at a redemption price of 112% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as:

 
at least 65% of the aggregate principal amount of the notes issued on February 8, 2008, remains outstanding after each such redemption; and
 
the redemption occurs within 180 days after the closing of the equity offering.

The notes also provide that we may, at our option, redeem all or part of the notes, at any time prior to February 15, 2013, at the make-whole price set forth in the indenture, and on or after February 15, 2013, at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption.  Further, the indenture provides that upon a change of control, we must give holders of the notes the opportunity to put their notes to us for repurchase at a repurchase price of 101% of the principal amount, plus accrued and unpaid interest.

In connection with the issuance of the notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for other freely tradable notes and to use commercially reasonable efforts to cause the registration statement to become effective on or prior to February 7, 2009.  On April 24, 2008, we filed the related registration statement on Form S-4.  The registration statement was declared effective May 23, 2008.

7.     ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with our working interest in oil and gas properties are as follows:

   
Amount
 
   
(in thousands)
 
Beginning balance at December 31, 2008
  $ 23,086  
Obligations assumed with development activities and acquisitions
    541  
Accretion expense
    335  
Ending balance at March 31, 2009
  $ 23,962  

Approximately $0.1 million of the asset retirement obligations was classified as short-term and included in other accrued expenses as of March 31, 2009, and December 31, 2008.
 
8.     COMMITMENTS AND CONTINGENCIES

 
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Drilling and Development Agreements.  In connection with the acquisition of oil and gas properties in October 2007 from an unaffiliated party, we are obligated to drill 100 wells in the Appalachian Basin by January 2016.  We will retain a majority interest in each well drilled.  For each well we fail to drill, we are obligated to pay to the seller liquidated damages of $25,000 per undrilled well for a total contingent obligation of $2.5 million or reassign to the seller the interest acquired in the number of undrilled well locations.  As of March 31, 2009, we have drilled 28 wells pursuant to this agreement.

We have entered into contracts that provide firm transportation, sales and processing charges on pipeline systems which we transport or sell our natural gas and the natural gas of other companies, working interest owners and our affiliated partnerships.  The remaining terms of the contracts range from two to 14 years and require us to pay these transportation and processing charges whether the required volumes are delivered or not.

The following table sets forth gross information about long-term firm sales, processing and transportation agreements for pipeline capacity, which require a demand charge whether volumes are delivered or not. We record in our financial statements only our share of costs 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.


Type of Arrangement
 
Location
 
Average
Annual
Volume
(MMbtu)
 
Expiration
Date
             
Firm sales and processing
 
Grand Valley
 
 23,218,287
 
May 2016
Firm transportation
 
NECO Area
 
 1,825,000
 
December 2010
Firm transportation
 
NECO Area
 
 1,825,000
 
December 2016
Firm transportation (1)
 
Appalachian Basin
 
 10,614,565
 
December 2022
             
(1) Contract is a precedent agreement and becomes effective when the planned pipeline is placed in service, estimated at this time to be 2012.  Contract is null and void if pipeline is not completed.
 
In September 2008, we entered into a pipeline and processing plants expansion agreement with an unrelated party, who is currently the purchaser of the majority of our Wattenberg Field natural gas production.  Pursuant to the agreement, we agreed to make a capital investment of $60 million, for our own benefit, over a three-year period commencing on January 1, 2009, to develop or facilitate production in our Wattenberg Field dedicated to this purchaser and, if the purchaser failed to diligently proceed with the pipeline and processing plants, we would be relieved of our obligations under the agreement.  In March 2009, we received from the unrelated party a notice waiving our commitment and stating that the pipeline and processing plant expansions were either on hold or had been delayed.  The waiver relieves us of the $60 million capital investment obligation.

Drilling Rig Contracts.  In order to secure the services for drilling rigs, we have commitments for the use of two drilling rigs with a drilling contractor.  The commitments call for a minimum commitment of $12,500 daily for a specified amount of time if we cease to use the drilling rigs and a maximum commitment of $40,680 daily for a specified amount of time for daily use of the drilling rigs.  One of the commitments expires in August 2009 and the other in July 2010.  In January 2009, based on our decision to temporarily cease drilling operations in the Piceance Basin, we demobilized one of these rigs.  As of March 31, 2009, we have an outstanding minimum commitment for $3.1 million and an outstanding maximum commitment for $12.2 million, which includes $3.2 million related to a rig sublet to a third party and remains our obligation should the third party default on terms of the sublet agreement.

 
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Litigation.

We are involved in various legal proceedings that we consider normal to our business. Although the results cannot be known with certainty, we believe that we have properly accrued reserves.

Colorado Royalty.  On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Company in the District Court, Weld County, Colorado alleging that we underpaid royalties on natural gas produced from wells operated by us in parts of the State of Colorado (the “Droegemueller Action”).  The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases.  We removed the case to Federal Court on June 28, 2007.  On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Company, on behalf of itself and the partnerships for which the Company is the managing general partner.  Based on the settlement terms, the settlement amount payable by the Company is $5.8 million.  Such moneys, in addition to moneys related to the settlement on behalf of the partnerships for which the Company is the managing general partner, were deposited in an escrow account on November 3, 2008.  We have accrued as of March 31, 2009, and included in other accrued expenses in our accompanying condensed consolidated balance sheets, a related $5.8 million litigation reserve.  We believe that the amount accrued is adequate to satisfy this obligation.  Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008.  The final settlement was approved by the court on April 7, 2009.  Distributions from the escrow to the royalty owners are expected on or before June 7, 2009, unless the court approval of the settlement is appealed.

Colorado Stormwater Permit.  On December 8, 2008, we received a Notice of Violation/Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment, 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 four equal owners of Garden Gulch LLC, all of which are oil and gas companies operating in the Piceance region of Colorado.  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.  No civil penalties have been imposed or requested at this time.  Given the preliminary stage of this proceeding and the inherent uncertainty in administrative actions of this nature, the Company is unable to predict the ultimate outcome of this administrative action at this time.

West Virginia Royalty.  On January 21, 2009, a lawsuit was filed in West Virginia state court in Barbour County, styled Beymer v. Petroleum Development Corporation and Riley National Gas Company, CA No. 09-C-3 (“Beymer lawsuit”), alleging a class action on behalf of lessors for failure to properly pay royalties.  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 January 27, 2009, another suit was filed in West Virginia state court in Harrison County, styled Gobel v. Petroleum Development Corporation, CA No. 09-C-40, alleging a class action with allegations similar to those alleged in the Beymer lawsuit.  Both cases have been removed to federal court in the Northern District of West Virginia.  In late April 2009, the federal judges for the respective cases approved jointly filed motions and stipulations providing for, among other things, a 180 day stay to explore settlement opportunities.

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 on our financial position, results of operations or liquidity.

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), if repurchase is requested by investors, subject to our financial ability to do so.  The maximum annual repurchase obligation as of March 31, 2009, was approximately $15.7 million.  We believe we have adequate liquidity to meet this obligation.  For the quarter ended March 31, 2009, we paid $0.9 million under this provision for the purchase of partnership units.

Employment Agreements with Executive Officers.  We have employment agreements with our Chief Executive Officer, Chief Financial Officer, Chief Accounting 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 termination benefits.

 
17

 
Index
 
In the event of termination following a change of control of the Company, or where the Company terminates the executive officer without cause or where an executive officer terminates employment for good reason, the severance benefits range from two times to three times the sum of his highest annual base salary during the previous two years of employment immediately preceding the termination date and his highest annual bonus received during the same two year period.  For this purpose a “change of control” corresponds to the definition of “change of control” under Section 409A of the Internal Revenue Code of 1986 (IRC) and the supporting treasury regulations.  The executive officer is also entitled to (i) vesting of any unvested equity compensation (excluding all long-term incentive 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 up to 18 months, 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 any bonus (only for periods completed and accrued, but not paid), incentive, deferred, retirement or other compensation, and to provide any other benefits, which have been earned or become payable as of the termination date but which have not yet been paid or provided.

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, bonus and incremental retirement payment prorated for the portion of the year that the executive officer is employed by the Company, provided, however, that with respect to the bonus, for certain executive officers, there shall 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 shall 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 shall be payable in a lump sum and shall be equal to the compensation and other benefits that would otherwise have been paid for a six month period following the termination date plus a pro-rated portion of the performance bonus.

Derivative Contracts.  We would be exposed to oil and natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to our derivative instruments or the counterparties to our gas marketing contracts not perform.  Nonperformance is not anticipated.  We have had no counterparty default losses.

Partnership Casualty Losses.  As Managing General Partner of 33 partnerships, we have liability for any 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.

9.     STOCK-BASED COMPENSATION

We maintain equity compensation plans for officers, certain key employees and non-employee directors.  In accordance with the plans, awards may be issued in the form of stock options, stock appreciation rights, restricted stock, performance shares and performance units.  Through the date of this report, we have not issued any stock appreciation rights or performance units.

The following table provides a summary of the impact of our stock based compensation plans on the results of operations for the periods presented.

   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
             
Total stock-based compensation expense (1)
  $ 1,639     $ 1,792  
Income tax benefit
    (625 )     (691 )
                 
Net income impact
  $ 1,014     $ 1,101  
                 
                 
______________                
(1)      2008 includes $1.1 million related to a separation agreement with our former president.  
 
 
18

 
Index
 
Stock Option Awards.  We have granted stock options pursuant to various stock compensation plans.  Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period.  There were no stock options awarded for the three months ended March 31, 2009.  For the prior year period, pursuant to a separation agreement with our former president, we modified options to purchase 4,678 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award.  The incremental change in fair value per share of the modified awards was immaterial.   The fair value of options modified in 2008, were estimated to approximate fair value on the date of modification due to the short-term nature of the award.

The following table provides a summary of our stock option award activity for the three months ended March 31, 2009:


   
Number of
Shares
Underlying
Options
   
Weighted
Average
Exercise
Price
Per Share
   
Weighted
Average
Remaining
Contractual
Term
(in years)
 
                   
Outstanding at December 31, 2008
    18,351     $ 41.68       6.8  
                         
Outstanding at March 31, 2009
    18,351       41.68       6.6  
                         
Vested and expected to vest at March 31, 2009
    18,351       41.68       6.6  
                         
Exercisable at March 31, 2009
    14,709       41.02       6.4  


The intrinsic values of the options outstanding and exercisable at March 31, 2009, and December 31, 2008, were nil as the closing market price of our common stock at the respective date exceeded the exercise price of the options.  Total compensation cost related to stock options granted and not yet recognized in our condensed consolidated statement of operations as of March 31, 2009, was $0.1 million.  This cost is expected to be recognized over a weighted average period of 1.5 years.

Restricted Stock Awards

We began issuing shares of restricted common stock to employees in 2004 and to non-employee directors in 2005.  Vesting conditions for our restricted stock awards are either time-based or market-based.

 
Time-Based Awards.  The fair value of the time-based awards is amortized ratably over the requisite service period, generally over four years, and five years in connection with succession related grants to executive officers in March 2008.  Time-based awards for non-employee directors generally vest on July 1st of the year following the date of the grant.

The following table sets forth the changes in non-vested time-based awards for the three months ended March 31, 2009:

         
Weighted Average
 
         
Grant-Date
 
   
Shares
   
Fair Value
 
Non-vested at December 31, 2008
    218,060     $ 52.59  
Granted
    102,469       12.12  
Vested
    (18,508 )     61.44  
Non-vested at March 31,  2009
    302,021       38.32  

The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our condensed consolidated statement of operations as of March 31, 2009, is $8.8 million.  This cost is expected to be recognized over a weighted-average period of 2.9 years.  For the three months ended March 31, 2008, pursuant to a separation agreement with our former president, we modified time-based awards to vest 10,954 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award, resulting in an increase in the original fair value of $0.2 million.

 
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Index
 
Market-Based Awards.  The fair value of the market-based awards is amortized ratably over the requisite service period, primarily over three years for market-based awards.  The market-based shares vest only upon the achievement of certain per share price thresholds and continuous employment during the vesting period.  All compensation cost related to the market based-awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved.  In March 2008, pursuant to a separation agreement with our former president, we modified market-based awards to vest 1,539 shares by accelerating the vesting schedule, none of which would have vested pursuant to the original terms of the award.  The incremental change in fair value per share of the modified awards was immaterial.  The fair value of options modified in 2008 were estimated to approximate fair value on the date of modification due to the short-term nature of the award.

The weighted average grant date fair value per market-based share, including shares modified in 2008 pursuant to an agreement with our former president, was computed using the Monte Carlo pricing model using the following weighted average assumptions:

   
Three Months Ended March 31,
   
2009
 
2008
         
Expected term of award
 
3 years
 
3 years
Risk-free interest rate
 
2.0%
 
2.3%
Volatility
 
59.0%
 
45.6%
Weighted average grant date fair value per share
 
$6.47
 
$45.85


For 2009, expected volatility was based on a blend of our historical and implied volatility and, for 2008, was based on our historical volatility.  The expected lives of the awards were based on the requisite service period.  The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant or modification and extrapolated to approximate the life of the award.  We do not expect to pay dividends, nor do we expect to declare dividends in the foreseeable future.

The following table sets forth the changes in non-vested market-based awards for the three months ended March 31, 2009:


         
Weighted Average
 
         
Grant-Date
 
   
Shares
   
Fair Value
 
Non-vested at December 31, 2008
    72,683     $ 41.62  
Granted
    28,130       6.47  
Non-vested at March 31, 2009
    100,813       31.81  


The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our condensed consolidated statement of operations as of March 31, 2009, is $1.2 million.  This cost is expected to be recognized over a weighted-average period of 1.7 years.

10.   INCOME TAXES

We evaluate our estimated annual effective income tax rate on a quarterly basis based on current and forecasted business 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.  Tax expenses or tax benefits unrelated to current year ordinary income or loss are recognized entirely in the period identified as discrete items of tax.  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.

The loss we realized for the three months ended March 31, 2009, exceeds our projected loss for the year.  As a result, we calculated our first quarter tax benefit by multiplying the current period loss by the statutory tax rate and then adding other statutory tax benefits such as percentage depletion.  This required tax calculation limited the tax benefit realized during the first quarter by $1.6 million.  No similar limitation calculation was required for the three months ended March 31, 2008.  There were no significant discrete items recorded in the first quarter of 2009 or 2008.

 
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Index

As of March 31, 2009, we had a gross liability for uncertain tax benefits of $1.2 million, of which $0.1 million was recorded in the current three month period.  If recognized, $0.9 million of this liability would affect our effective tax rate.  This liability is reflected in federal and state income taxes payable in our accompanying condensed consolidated balance sheet.  The increase in the liability recorded in the current period is primarily related to an uncertain tax benefit recorded with respect to the 2009 tax year.  The Internal Revenue Service ("IRS") has substantially completed its examination of our 2005 and 2006 tax years, and we currently expect this examination to be completed during 2009.  Therefore, we expect the liability for uncertain tax benefits to decrease during the next twelve month period as items are either resolved without change or converted to amounts due to the IRS.

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.  Administrative review of our Colorado refund claims, filed through amended returns to implement 2008 state tax strategies, is still pending.  We have received the applicable West Virginia refunds claimed via amended returns filed in 2008.

11.   EARNINGS PER SHARE

The following is a reconciliation of basic and diluted weighted average shares outstanding:

   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
             
Weighted average common shares outstanding- basic
    14,793       14,738  
Weighted average common and common share equivalents outstanding - diluted
    14,793       14,738  

For the three months ended March 31, 2009 and 2008, the weighted average common shares outstanding for both basic and diluted were the same because the effect of dilutive securities were anti-dilutive due to our net loss for each of 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.

   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect:
           
Unamortized portion of restricted stock
    260       70  
Stock options
    18       38  
Non employee director deferred compensation
    7       6  
Total anti-dilutive common share equivalents
    285       114  


12.  BUSINESS SEGMENTS

We separate our operating activities into four segments:  oil and gas sales, natural gas marketing, well operations and pipeline income and oil and gas well drilling.  All material inter-company accounts and transactions between segments have been eliminated.

Oil and Gas Sales. Our oil and gas sales segment represents revenues and expenses from the production and sale of oil and natural gas.  Segment revenue includes oil and gas price risk management, net.  Segment income (loss) consists of oil and gas sales revenues less its allocated share of oil and gas production and well operations cost, exploration expense, direct general and administrative expense and DD&A expense.  Segment DD&A expense was $33.1 million and $20.3 million for the three months ended March 31, 2009 and 2008, respectively.

Natural Gas Marketing Activities. Our natural gas marketing segment is composed of our wholly owned subsidiary, RNG, through which we purchase, aggregate and resell natural gas produced by us and others.  Segment income primarily represents sales from natural gas marketing activities and direct interest income less costs of natural gas marketing activities, direct general and administrative expense.

Well Operations and Pipeline Income.  We charge our affiliated partnerships and other third parties competitive industry rates for well operations and natural gas gathering.  Segment revenue includes monthly operating and gas gathering fees we charge for each well in which we
 
 
21

 
operate that is owned by others, including our affiliated partnerships.  Segment income consists of well operations and pipeline income revenues less its allocated share of oil and gas production and well operations cost and direct DD&A expense.
 
Oil and Gas Well Drilling. We drill natural gas wells for affiliated drilling partnerships and retain an interest in each well. Our drilling and development segment reflects results of drilling and development activities conducted for affiliated and non-affiliated parties.  Segment income consists of oil and gas well drilling revenues less cost of oil and gas well drilling.  We last sponsored a drilling partnership in the fall of 2007, and substantially completed our last drilling services for that partnership in the fall of 2008.  We do not currently have any plans to sponsor additional drilling partnerships.

Other.  This segment includes unallocated corporate general administrative expense, direct DD&A expense, direct interest income and interest expense.

Segment information for the three months ended March 31, 2009 and 2008, is presented below.


   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
Revenues:
           
Oil and gas sales
  $ 63,425     $ 29,336  
Natural gas marketing
    22,389       23,325  
Well operations and pipeline income
    2,796       2,352  
Oil and gas well drilling
    193       3,083  
Unallocated amounts
    42       3  
Total
  $ 88,845     $ 58,099  
                 
Segment income (loss) before income taxes:
               
Oil and gas sales
  $ 10,231     $ (11,994 )
Natural gas marketing
    514       1,332  
Well operations and pipeline income
    627       592  
Oil and gas well drilling
    48       3,005  
Unallocated amounts
    (21,138 )     (15,065 )
Total
  $ (9,718 )   $ (22,130 )


   
March 31, 2009
   
December 31, 2008
 
   
(in thousands)
 
Segment assets:
           
Oil and gas sales
  $ 1,260,633     $ 1,247,687  
Natural gas marketing
    28,489       50,117  
Well operations and pipeline income
    62,063       50,052  
Oil and gas well drilling
    376       2,028  
Unallocated amounts
    48,205       52,820  
Total
  $ 1,399,766     $ 1,402,704  

 
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Index

Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

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 and Section 21E of the Securities Exchange Act of 1934 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 oil and natural gas 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 oil and natural gas;
 
·
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;
 
·
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;
 
·
the effect of natural gas and oil derivatives 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, 2008, and our other filings with the Securities and Exchange Commission (“SEC”) and public disclosures.  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.

 
23

 
Index
 
Results of Operations

Summary of Operations

The following table sets forth selected information regarding our results of operations, including production volumes, oil and gas sales, average sales prices received, average sales price including realized derivative gains and losses, average lifting cost, other operating income and expenses for the three months ended March 31, 2009, or first quarter 2009, and the three months ended March 31, 2008, or first quarter 2008.
 

   
Summary Operating Results
 
   
Three Months Ended March 31,
 
   
2009
   
2008
   
Change
 
Production (1)
           
Oil (Bbls)
    343,884       255,452       34.6 %
Natural gas (Mcf)
    9,090,261       6,946,822       30.9 %
Natural gas equivalent (Mcfe) (2)
    11,153,565       8,479,534       31.5 %
                         
Oil and Gas Sales  (in thousands)
                       
Oil sales
  $ 12,989     $ 20,727       -37.3 %
Gas sales
    29,334       50,919       -42.4 %
Provision for underpayment of gas sales
    (2,581 )     -       *  
Total oil and gas sales
  $ 39,742     $ 71,646       -44.5 %
                         
Realized Gain (Loss) on Derivatives, net (in thousands)
                       
Oil derivatives
  $ 7,294     $ (1,306 )     *  
Natural gas derivatives
    29,332       (1,105 )     *  
Total realized gain (loss) on derivatives, net
  $ 36,626     $ (2,411 )     *  
                         
Average Sales Price (excluding realized gains/losses on derivatives)
                       
Oil (per Bbl)
  $ 37.77     $ 81.14       -53.5 %
Natural gas (per Mcf)
  $ 3.23     $ 7.33       -55.9 %
Natural gas equivalent (per Mcfe)
  $ 3.79     $ 8.45       -55.1 %
                         
Average Sales Price (including realized gains/losses on derivatives)
                       
Oil (per Bbl)
  $ 58.98     $ 76.03       -22.4 %
Natural gas (per Mcf)
  $ 6.45     $ 7.17       -10.0 %
Natural gas equivalent (per Mcfe)
  $ 7.08     $ 8.16       -13.3 %
                         
Average Lifting Cost per Mcfe (3)
  $ 0.93     $ 1.13       -17.7 %
                         
Other Operating Income (4) (in thousands)
                       
Natural gas marketing activities
  $ 511     $ 1,204       -57.6 %
Oil and gas well drilling
  $ 48     $ 3,005       -98.4 %
                         
Costs and Expenses (in thousands)
                       
Exploration expense
  $ 5,643     $ 4,283       31.8 %
General and administrative expense
  $ 12,094     $ 9,823       23.1 %
Depreciation, depletion and amortization
  $ 34,344     $ 21,131       62.5 %
                         
Interest Expense (in thousands)
  $ 8,383     $ 4,932       70.0 %
                         
* Percentage change not meaningful or equal to or greater than 250%
Amounts may not calculate due to rounding

_______________
(1)
Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own.
(2)
A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
(3)
Lifting costs represent oil and gas operating expenses which exclude production taxes.
(4)
Includes revenues and operating expenses.

 
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Index

During first quarter 2009, we experienced the continuation of dramatic declines in oil and natural gas commodity prices from late July of last year.  Last year was marked with a series of unprecedented events: oil and natural gas prices soared to near record highs through July; then, in the midst of U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped by almost half.  While we certainly felt the impact of these events, we believe that we were successful in managing our operations in such a manner that we were able to minimize the negative impacts.  As production increased to 11.2 Bcfe for first quarter 2009 compared to 8.5 Bcfe for first quarter 2008, an increase of 31.5%, our average sales price declined $4.66 per Mcfe.  However, our derivative position eased the impact of the fall in oil and natural gas prices.  Our realized derivative gains for first quarter 2009 of $36.6 million added an average of $3.29 per Mcfe produced during first quarter 2009, somewhat easing the dramatic drop in prices.  At March 31, 2009, we estimate the net fair value of our open derivative positions, excluding the derivative positions attributed to our affiliated partnerships, to be $104.5 million.  See the Liquidity and Capital Resources discussion below for the steps we are taking in this uncertain economic environment.

Depressed commodity prices for first quarter 2009 as compared to the higher prices in first quarter 2008 were the primary contributors to the $66 million change in oil and gas price risk management.  Of the $66 million change, $57.5 million was related to the change in unrealized gains and losses on derivative instruments.  Unrealized gains and losses are non-cash items and these non-cash charges to our consolidated statement of operations will continue to fluctuate with the fluctuation in commodity prices until the positions mature or are closed, at which time they will become realized or cash items.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under FAS No. 133 may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.

The table below, which demonstrates the volatility in the markets’ projected commodity prices, sets forth the average NYMEX and CIG prices for the next 24 months (forward curve) from the selected dates.


          December 31,     June 30,     December 31,    
March 31,
 
Commodity
 
Index
 
2007
   
2008
   
2008
   
2009
 
                             
Natural gas:
 
NYMEX
  $ 8.12     $ 12.52     $ 6.62     $ 5.44  
   
CIG
     6.78        8.86        4.49       4.15  
Oil:
 
NYMEX
     90.79        140.15        57.49       59.35  


Oil and Gas Sales Activity

The following tables set forth oil and natural gas production and sales activity by area.


   
Three Months Ended March 31,
 
   
2009
   
2008
   
Change
 
Production
                 
Oil (Bbls)
                 
Rocky Mountain Region
    341,357       253,533       34.6 %
Appalachian Basin
    1,704       1,096       55.5 %
Michigan Basin
    823       823       0.0 %
Total
    343,884       255,452       34.6 %
Natural gas (Mcf)
                       
Rocky Mountain Region
    7,828,763       5,599,765       39.8 %
Appalachian Basin
    975,681       967,620       0.8 %
Michigan Basin
    285,817       379,437       -24.7 %
Total
    9,090,261       6,946,822       30.9 %
Natural gas equivalent (Mcfe)
                       
Rocky Mountain Region
    9,876,905       7,120,963       38.7 %
Appalachian Basin
    985,905       974,196       1.2 %
Michigan Basin
    290,755       384,375       -24.4 %
Total
    11,153,565       8,479,534       31.5 %

 
25

 
Index
 
   
Three Months Ended March 31,
 
   
2009
   
2008
   
Change
 
Average Sales Price (excluding realized derivative gains/losses)
                 
Oil (per Bbl)
                 
Rocky Mountain Region
  $ 37.78     $ 81.08       -53.4 %
Appalachian Basin
    37.06       88.71       -58.2 %
Michigan Basin
    36.90       96.03       -61.6 %
Weighted average price
    37.77       81.14       -53.5 %
Natural gas (per Mcf)
                       
Rocky Mountain Region
  $ 2.95     $ 7.13       -58.6 %
Appalachian Basin
    5.04       8.41       -40.1 %
Michigan Basin
    4.24       7.63       -44.4 %
Weighted average price
    3.23       7.33       -55.9 %
Natural gas equivalent (per Mcfe)
                       
Rocky Mountain Region
  $ 3.65     $ 8.49       -57.0 %
Appalachian Basin
    5.04       8.45       -40.4 %
Michigan Basin
    4.26       7.74       -45.0 %
Weighted average price
    3.79       8.45       -55.1 %

While our production increased to 11.2 Bcfe for first quarter 2009 from 8.5 Bcfe for first quarter 2008, our oil and gas sales revenue decreased $31.9 million quarter-to-quarter, primarily due to the dramatic decline in commodity prices, partially offset by increased volumes.  Approximately $39.5 million of the decrease in revenue was due to pricing, offset in part by increased production, which contributed $10.1 million.  The decrease in oil and gas sales revenue was offset by realized derivative gains for first quarter 2009 of $36.6 million, see Oil and Gas Price Risk Management, Net discussion below.

Oil and Natural Gas Pricing. Financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production effectively.  Oil and natural gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on our financial results.  Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Like most producers in the region, we rely on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control.  Oil pricing is also driven strongly by supply and demand relationships.

The price we receive for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which generally includes gas sold at CIG prices as well as gas sold at Mid-Continent or other nearby region prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based.

Although 86.1% of our natural gas production for first quarter 2009 is produced in the Rocky Mountain Region, much of our Rocky Mountain natural gas pricing is based upon other indices in addition to CIG.  The table below identifies the pricing basis of our oil and natural gas sales based on production for first quarter 2009.  The pricing basis is the index that most closely relates to the price under which our oil and natural gas is sold.


Energy Market Exposure
For the Three Months Ended March 31, 2009
Area
 
Pricing Basis
 
Commodity
 
Percent of
 Production
                 
Piceance/Wattenberg
 
Colorado Interstate Gas (CIG)
 
Gas
   
37%
 
Colorado/North Dakota
 
NYMEX
 
Oil
   
18%
 
Piceance
 
San Juan Basin/Southern California
 
Gas
   
16%
 
NECO
 
Mid Continent (Panhandle Eastern)
 
Gas
   
12%
 
Appalachian
 
NYMEX
 
Gas
   
9%
 
Wattenberg
 
Colorado Liquids
 
Gas
   
4%
 
Michigan
 
Mich-Con/NYMEX
 
Gas
   
3%
 
Other
 
Other
 
Gas/Oil
   
1%
 
             
100%
 

 
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Index

Oil and Gas Production and Well Operations Costs.  Oil and gas production and well operations cost includes our lifting cost, production taxes, the cost to operate wells and pipelines for our affiliated partnerships and other third parties (whose income is included in well operations and pipeline income) and certain production and engineering staff related overhead costs.

 
   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
             
Lifting cost, excluding production taxes
  $ 10,321     $ 9,610  
Production taxes
    1,913       5,015  
Costs for well operations segment
    1,643       1,362  
Overhead and other production expenses
    2,339       2,145  
Total oil and gas production and well operations cost
  $ 16,216     $ 18,132  


Lifting Costs.  Lifting costs per Mcfe, excluding production taxes which fluctuate with oil and natural gas prices, decreased 17.7% to $0.93 per Mcfe for first quarter 2009 from $1.13 per Mcfe for first quarter 2008.  The decrease is primarily due to a 31.5% increase in production, which allows us to spread the fixed portion of our production costs over an increased volume, thereby lowering the per unit cost.  Additionally, lower oil and natural gas prices have also put pressure on oil and gas service providers to reduce their rates, for which we have started seeing the benefits.  We expect a downward trend to continue until commodity prices rebound.

Production Taxes.  Production taxes decreased $3.1 million or 61.9% to $1.9 million.  This decrease is primarily related to the 40.9% decrease in oil and gas sales along with a decrease of $1.1 million in our estimated 2008 taxes.

Oil and Gas Price Risk Management, Net


   
Three Months Ended March 31,
 
   
2009
   
2008
 
   
(in thousands)
 
Oil and gas price risk management, net:
           
Realized gain (loss)
           
Oil
  $ 7,294     $ (1,306 )
Natural gas
    29,332       (1,105 )
Total realized gain, net
    36,626       (2,411 )
Reclassification of realized (gains) losses included in prior periods unrealized
    (30,193 )     351  
Unrealized gains (losses) for the period
    17,250       (40,250 )
    $ 23,683     $ (42,310 )


The net unrealized gain for first quarter 2009 of $17.3 million was primarily due to a $33 million net unrealized gain from our commodity derivatives offset in part by a decrease in fair value of our CIG basis protection swaps of $15.7 million.  The net unrealized gain from commodity derivatives resulted from the continued decline in commodity prices during the first quarter.  The unrealized loss from our CIG basis protection swaps resulted from a more significant decline in NYMEX pricing compared to CIG pricing.  The realized gains from commodity derivatives resulted from the current realized prices being below our swaps and floor contract prices.

Oil and gas price risk management, net includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our oil and natural gas production.  Oil and gas price risk management, net does not include derivative transactions related to natural gas marketing activities, which are included in sales from and cost of natural gas marketing activities.  See Note 3, Fair Value Measurements, and Note 4, Derivative Financial Instruments, to the accompanying condensed consolidated financial statements for additional details of our derivative financial instruments.

Oil and Gas Derivative Activities.  We use various derivative instruments to manage fluctuations in oil and natural gas prices.  We have in place a series of collars, fixed price swaps and basis swaps on a portion of our oil and natural gas production.  Under the collar arrangements, if the applicable index rises above the ceiling price or swap, we pay the counterparty; however, if the index drops below the floor or swap, the counterparty pays us.

 
27

 
Index

The following table identifies our derivative positions (excluding the derivative positions allocated to our affiliated partnerships) related to oil and gas sales activities in effect as of March 31, 2009, on our production by area.  Our production volumes for first quarter 2009 were 343,884 Bbls of oil and 9.1 Bcf of natural gas.  No new positions have been entered into subsequent to March 31, 2009, through the date of this filing.

 

   
Floors
   
Ceilings
   
Swaps (Fixed Prices)
   
Basis Protection Contracts
   
Fair Value
 
         
Weighted
         
Weighted
         
Weighted
         
Weighted
   
At
 
Commodity/
 
Quantity
   
Average
   
Quantity
   
Average
   
Quantity
   
Average
   
Quantity
   
Average
   
March 31,
 
Index/
 
(Gas-MMbtu
   
Contract
   
(Gas-MMbtu
   
Contract
   
(Gas-MMbtu
   
Contract
   
(Gas-MMbtu
   
Contract
   
2009
 
Operating Area
 
Oil-Bbls)
   
Price
   
Oil-Bbls)
   
Price
   
Oil-Bbls)
   
Price
   
Oil-Bbls)
   
Price
   
(in thousands)
 
                                                       
Natural Gas
                                                     
Rocky Mountain Region
                                                     
CIG