form10q.htm


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

FORM 10-Q


x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2008

OR

o Transition Report Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934
For the transition period from   to

Commission File Number: 000-07246

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.)

120 Genesis Boulevard
Bridgeport, West Virginia  26330
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:  (304) 842-3597

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x    No o
 
Indicate by check mark whether the registrant 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  o
Accelerated filer  x
Non-accelerated filer  o
Smaller reporting company  o

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: 14,848,954 shares of the Company's Common Stock ($.01 par value) were outstanding as of May 1, 2008.
 


 
 

 

PETROLEUM DEVELOPMENT CORPORATION

INDEX


 
PART 1 – FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements (unaudited)
 
 
2
 
3
 
4
 
5
Item 2.
17
Item 3.
28
Item 4.
30
     
     
     
 
PART II – OTHER INFORMATION
 
     
Item 1.
31
Item 1A.
31
Item 2.
32
Item 3.
32
Item 4.
32
Item 5.
32
Item 6.
32
     
     
 
33
 
1


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,
 
   
2008
   
2007*
 
Assets
             
Current assets:
             
Cash and cash equivalents
  $ 26,202     $ 84,751  
Accounts receivable, net
    60,699       60,024  
Accounts receivable - affiliates
    34,557       11,537  
Fair value of derivatives
    10,408       4,817  
Other current assets
    38,202       30,664  
Total current assets
    170,068       191,793  
Properties and equipment, net
    869,967       845,864  
Other assets
    35,432       12,822  
Total assets
  $ 1,075,467     $ 1,050,479  
                 
Liabilities and shareholders' equity
               
Current liabilities:
               
Accounts payable
  $ 84,924     $ 88,502  
Accounts payable - affiliates
    4,401       3,828  
Federal and state income taxes payable
    996       901  
Fair value of derivatives
    57,518       6,291  
Advances for future drilling contracts
    40,911       68,417  
Funds held for future distribution
    57,223       39,823  
Other accrued expenses
    31,195       34,243  
Total current liabilities
    277,168       242,005  
Long-term debt
    203,000       235,000  
Deferred income taxes
    141,873       136,490  
Other liabilities
    73,141       40,699  
Total liabilities
    695,182       654,194  
                 
Commitments and contingencies
               
                 
Minority interest in consolidated limited liability company
    743       759  
                 
Total shareholders' equity
    379,542       395,526  
Total liabilities and shareholders' equity
  $ 1,075,467     $ 1,050,479  
_______________
*Derived from audited 2007 balance sheet.


See accompanying notes to condensed consolidated financial statements.

2


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

   
Three Months Ended March 31,
 
   
2008
   
2007
 
             
Revenues:
           
Oil and gas sales
  $ 71,646     $ 34,016  
Sales from natural gas marketing activities
    23,325       21,987  
Oil and gas well drilling operations
    3,083       4,030  
Well operations and pipeline income
    2,352       3,298  
Oil and gas price risk management loss, net
    (42,310 )     (5,645 )
Other
    3       226  
Total revenues
    58,099       57,912  
                 
Costs and expenses:
               
Oil and gas production and well operations cost
    18,132       9,035  
Cost of natural gas marketing activities
    22,121       21,512  
Cost of oil and gas well drilling operations
    78       564  
Exploration expense
    4,283       2,678  
General and administrative expense
    9,823       7,424  
Depreciation, depletion and amortization
    21,131       13,074  
Total costs and expenses
    75,568       54,287  
                 
Income (loss) from operations
    (17,469 )     3,625  
Interest income
    271       1,143  
Interest expense
    (4,932 )     (831 )
                 
Income (loss) before income taxes
    (22,130 )     3,937  
Provision (benefit) for income taxes
    (8,202 )     1,436  
Net income (loss)
  $ (13,928 )   $ 2,501  
                 
Earnings (loss) per share
               
Basic
  $ (0.95 )   $ 0.17  
Diluted
  $ (0.95 )   $ 0.17  
Weighted average common shares outstanding
               
Basic
    14,738       14,726  
Diluted
    14,738       14,854  


See accompanying notes to condensed consolidated financial statements.

3


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

   
Three Months Ended March 31,
 
   
2008
   
2007
 
             
Cash flows from operating activities:
           
Net income (loss)
  $ (13,928 )   $ 2,501  
Adjustments to net income (loss) to reconcile to cash  provided by (used in) operating activities:
               
Deferred income taxes
    (9,738 )     (3,379 )
Depreciation, depletion and amortization
    21,131       13,074  
Amortization of debt issuance costs
    256       -  
Accretion of asset retirement obligation
    304       232  
Exploratory dry hole costs
    1,100       194  
Expired and abandoned leases
    442       53  
Unrealized loss on derivative transactions
    39,334       6,636  
Changes in assets and liabilities
    8,401       (52,532 )
Other
    1,487       483  
Net cash provided by (used in) operating activities
  $ 48,789     $ (32,738 )
                 
Cash flows from investing activities:
               
Capital expenditures
    (64,321 )     (13,378 )
Acquisitions
    -       (201,488 )
Decrease in restricted cash for property acquisition
    -       191,452  
Other
    204       385  
Net cash used in investing activities
    (64,117 )     (23,029 )
                 
Cash flows from financing activities:
               
Proceeds from credit facility
    42,000       70,000  
Repayment of credit facility
    (277,000 )     (147,000 )
Proceeds from senior notes
    200,101       -  
Payment of debt costs
    (4,486 )     -  
Proceeds from exercise of stock options
    367       152  
Excess tax benefits from stock based compensation
    154       -  
Purchase of treasury stock
    (4,357 )     (135 )
Net cash used in financing activities
    (43,221 )     (76,983 )
                 
Net decrease in cash and cash equivalents
    (58,549 )     (132,750 )
Cash and cash equivalents, beginning of period
    84,751       194,326  
Cash and cash equivalents, end of period
  $ 26,202     $ 61,576  
                 
                 
Supplemental disclosure of cash flow information of cash payments for:
               
Interest
  $ 2,721     $ 2,205  
Income taxes
    2,774       24,781  
Supplemental schedule of non-cash investing and financing activities:
               
Change in deferred tax liability resulting from reallocation of acquisition purchase price
    -       4,188  
Changes in accounts payable related to the acquisitions of partnerships
    -       668  
Changes in accounts payable related to purchase of properties and equipment
    (11,383 )     17,563  
Asset retirement obligation, with a corresponding increase to oil and gas properties, net of disposals
    133       4,738  
Changes in accounts payable related to debt costs
    306       -  

 
See accompanying notes to condensed consolidated financial statements.

4


Petroleum Development Corporation
Notes to Condensed Consolidated Financial Statements
March 31, 2008
(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 interim 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.  Minority interest in earnings and ownership has been recorded for the percentage of the LLC we do not own for each of the applicable periods.  We account for our investment in interests in oil and natural gas limited partnerships under the proportionate consolidation method.  Accordingly, our accompanying interim 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 is eliminated.

The accompanying interim 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 interim 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 interim results of operations for the three months ended March 31, 2008, and the interim cash flows for the same interim period, are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying interim 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, 2007, as filed with the SEC on March 20, 2008 ("2007 Form 10-K").

2.  RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

We adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 157, Fair Value Measurements, effective January 1, 2008.  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.  In February 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position ("FSP") FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 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).  Nonfinancial assets and liabilities for which we have not applied the provisions of SFAS No. 157 include those initially measured at fair value, including our asset retirement obligations.  As of the adoption date, we have applied the provisions of SFAS No. 157 to our recurring measurements and the impact was not material to our underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting.  We are currently evaluating the potential effect that the nonfinancial assets and liabilities provisions of SFAS No. 157 will have on our financial statements when adopted in 2009.  See Note 5 for further details on our fair value measurements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities.  SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007.  As of March 31, 2008, we had not elected, nor do we intend, to measure additional financial assets and liabilities at fair value.

5


In April 2007, the FASB issued FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39 ("FIN 39-1"), to amend certain portions of Interpretation 39.  FIN 39-1 replaces the terms "conditional contracts" and "exchange contracts" in Interpretation 39 with the term "derivative instruments" as defined in Statement 133.  FIN 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments.  FIN 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted.  The January 1, 2008, adoption of FSP FIN 39-1 had no impact on our financial statements.

Recently Issued Accounting Standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations ("SFAS No. 141R").  SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  SFAS No. 141R 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, SFAS No. 141R requires that acquisition-related costs be expensed as incurred.  The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date.  SFAS No. 141R amends SFAS 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.  SFAS No. 141R further amends SFAS 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 December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  Additionally, SFAS 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.  SFAS No. 160 is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  We do not expect the adoption of SFAS No. 160 to have a material effect on our financial statements and related disclosures.

In March 2008, the FASB issued SFAS 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.  SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  As SFAS No. 161 is disclosure related, we do not expect its adoption to have a material impact on our financial statements.

3.  PROPERTIES AND EQUIPMENT

   
March 31,
   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Properties and equipment, net:
           
Oil and gas properties (successful efforts method of accounting)
           
Proved
  $ 994,206     $ 953,904  
Unproved
    41,938       41,023  
Total oil and gas properties
    1,036,144       994,927  
Pipelines and related facilities
    23,023       22,408  
Transportation and other equipment
    27,389       23,669  
Land and buildings
    13,898       11,303  
Construction in progress (1)
    -       2,929  
      1,100,454       1,055,236  
Accumulated depreciation, depletion and amortization ("DD&A")
    (230,487 )     (209,372 )
                 
    $ 869,967     $ 845,864  
                 
(1) At December 31, 2007, includes costs primarily related to a new integrated oil and gas financial software system.
 
6


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 accompanying condensed consolidated balance sheets in accordance with FSP No. 19-1, Accounting for Suspended Well Costs.
 
         
Number
 
   
Amount
   
of Wells
 
   
(in thousands)
       
             
Beginning balance at December 31, 2007
  $ 2,300       3  
Additions to capitalized exploratory well costs  pending the determination of proved reserves
    4,483       7  
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
    -       -  
Capitalized exploratory well costs charged to expense
    (1,100 )     (1 )
Ending balance at March 31, 2008
  $ 5,683       9  

As of March 31, 2008, none of the nine suspended wells awaiting the determination of proved reserves have been capitalized for a period greater than one year.

4.  DERIVATIVE FINANCIAL INSTRUMENTS

We account for derivative financial instruments in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  Our derivative instruments do not qualify for use of hedge accounting under the provisions of SFAS No. 133.  Accordingly, we recognize all derivative instruments as either assets or liabilities on our accompanying condensed consolidated balance sheets at fair value.  Changes in the derivatives' fair values are recorded on a net basis in our accompanying condensed consolidated statements of operations in oil and gas price risk management, net, for changes in derivative instruments related to our oil and gas sales and in sales from and cost of natural gas marketing activities for changes in derivative instruments related to our natural gas marketing activities.

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 derivatives.  Our policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

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 instruments. As of March 31, 2008, our oil and natural gas derivative instruments were comprised of futures, swaps and collars.  These instruments generally consist of (i) New York Mercantile Exchange ("NYMEX") -traded natural gas futures contracts and option contracts for Appalachian and Michigan production, (ii) Panhandle Eastern Pipeline ("PEPL") -based contracts for Northeastern Colorado ("NECO") production, (iii) Colorado Interstate Gas Index ("CIG") -based contracts for other Colorado production and (iv) NYMEX-based swaps and collars for our Colorado oil production.

 
·
For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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

7


We purchase puts and set collars and fixed-price swaps for our own and affiliate partnerships’ production to protect against price declines in future periods while retaining some of the benefits of price increases.

With regard to our natural gas marketing activities, we enter into fixed-price physical purchase and sale agreements that are 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 virtually eliminate 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 highly effective in achieving the risk management objectives for which they were intended, although they are currently below market due to the continual rises in energy prices.

The following table summarizes our open derivative positions as of March 31, 2008.

Open Derivative Positions
As of March 31, 2008
(dollars in thousands, except average price data)


                               
Positions maturing in 12 months of March 31, 2008
 
Commodity
 
Type
 
Quantity
Gas-MMbtu
Oil-Barrels
   
Weighted
Average
Price
   
Total
Contract
Amount
   
Total
Fair Value
   
Quantity
Gas-MMbtu
Oil-Barrels
   
Weighted
Average
Price
   
Total
Contract
Amount
   
Fair Value -
Current
Portion
 
                                                     
Total positions in effect for oil and gas sales (1)
                                               
Natural gas
 
Cash settled option sales
    44,910,000     $ 9.06     $ 406,865     $ (15,187 )     28,670,000     $ 8.71     $ 249,760     $ (9,906 )
Natural gas
 
Cash settled option purchases
    44,910,000       7.05       316,566       10,968       28,670,000       7.65       219,266       3,805  
Natural gas
 
Cash settled futures/swaps purchases
    25,970,000       7.52       195,285       (34,241 )     23,900,000       7.42       177,442       (33,147 )
Oil
 
Cash settled futures/swaps purchases
    1,170,000       84.79       99,208       (14,147 )     620,000       84.48       52,375       (8,766 )
Oil
 
Cash settled option sales
    730,000       102.63       74,916       (7,052 )     -       -       -       -  
Oil
 
Cash settled option purchases
    730,000       70.00       51,100       2,690       -       -       -       -  
                                $ (56,969 )                           $ (48,014 )
                                                                     
Total positions in effect for natural gas marketing activities (2)
                                                               
Natural gas
 
Cash settled futures/swaps purchases
    245,030     $ 6.79     $ 1,663     $ 55       245,030     $ 6.79     $ 1,663     $ 55  
Natural gas
 
Cash settled futures/swaps sales
    4,551,300       8.65       39,391       (6,225 )     3,160,800       8.63       27,275       (5,655 )
Natural gas
 
Physical purchases
    4,351,300       8.93       38,856       7,429       2,960,800       8.96       26,528       6,548  
Natural gas
 
Physical sales
    35,030       9.45       331       (44 )     35,030       9.45       331       (44 )
                                $ 1,215                             $ 904  

(1)      The maximum term for the derivative positions is 35 months.
(2)      The maximum term for the derivative positions is 45 months.

In addition to including the gross assets and liabilities related to our share of oil and gas production, the above tables and our condensed consolidated balance sheets include the gross assets and liabilities related to derivative contracts we entered into on behalf of our affiliate partnerships as the managing general partner.  Our condensed consolidated balance sheets include the fair value of derivatives and a corresponding net receivable from the partnerships of $16.5 million at March 31, 2008, and a corresponding net receivable from the partnerships of $1.5 million at December 31, 2007.

The following table identifies the fair value of commodity based derivatives as classified in our condensed consolidated balance sheets.
   
March 31,
   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Classification in the Condensed Consolidated Balance Sheets:
           
Fair value of derivatives - current asset
  $ 10,408     $ 4,817  
Other assets - long-term asset
    10,734       193  
      21,142       5,010  
                 
Fair value of derivatives - current liability
    57,518       6,291  
Other liabilities - long-term liability
    19,378       93  
      76,896       6,384  
Net fair value of commodity based derivatives
  $ (55,754 )   $ (1,374 )
 
8


The following changes in the fair value of commodity based derivatives are reflected in the condensed consolidated statements of income:
   
Three Months Ended March 31,
 
   
2008
   
2007
 
Statement of income line item
 
Realized
   
Unrealized
   
Realized
   
Unrealized
 
   
(in thousands, gains/(losses))
 
                         
Oil and gas price risk management gain (loss), net (1)
  $ (2,411 )   $ (39,899 )   $ 580     $ (6,225 )
Sales from natural gas marketing activities
    486       (7,638 )     1,097       (3,298 )
Cost of natural gas marketing activities
    66       8,203       (174 )     2,887  
  _____________
(1)  Represents net realized and unrealized gains and losses on commodity based derivative instruments related to oil and gas sales.

5.  FAIR VALUE MEASUREMENTS

As described above in Note 2, in September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.  We adopted the provisions of SFAS No. 157 effective January 1, 2008.

Valuation hierarchy.  SFAS 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.  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.  Instruments included in Level 1 consist of our commodity derivatives for 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.  Instruments included in Level 3 consist of our commodity derivatives for CIG and PEPL based natural gas swaps, oil swaps, oil and natural gas options, and physical sales and purchases.

Determination of fair value.  We measure fair value 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.  Furthermore, while we believe these valuation methods are appropriate and consistent with that 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.

9


SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3.  The following table presents, for each hierarchy level, our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of March 31, 2008:
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
                         
Assets:
                       
Commodity based derivatives
  $ 55     $ -     $ 21,087     $ 21,142  
                                 
Liabilities
                               
Commodity based derivatives
    (14,011 )   $ -       (62,885 )   $ (76,896 )
                                 
Net fair value of commodity based derivatives
  $ (13,956 )   $ -     $ (41,798 )   $ (55,754 )


The following table sets forth a reconciliation of our Level 3 fair value measurements:

   
Derivatives (1)
 
   
(in thousands)
 
       
Balance at January 1, 2008
  $ (2,368 )
Total realized and unrealized gains or (losses), net:
       
Included in oil and gas price risk management, net
    (982 )
Included in sales from natural gas marketing activities
    (22 )
Included in cost of natural gas marketing activities
    (5 )
Purchases, sales, issuances and settlements, net
    (38,421 )
Balance at March 31, 2008
  $ (41,798 )
         
Total gains (losses) attributable to the change in unrealized gain (loss), net relating to assets still held as of March 31, 2008:
       
Included in oil and gas price risk management, net
  $ (1,009 )
Included in sales from natural gas marketing activities
    -  
Included in cost of natural gas marketing activities
    -  
Total
  $ (1,009 )
 _____________
(1)  Derivative assets and liabilities are presented on a net basis.

6.  LONG-TERM DEBT

Long-term debt consists of the following:
   
March 31, 2008
   
December 31, 2007
 
   
(in thousands)
 
             
Credit facility
  $ -     $ 235,000  
12% Senior notes due 2018
    203,000       -  
Total long-term debt
  $ 203,000     $ 235,000  

Credit facility

We have a credit facility with JPMorgan Chase Bank, N.A. ("JPMorgan") and BNP Paribas, as amended, dated as of November 4, 2005, with an activated commitment of $234.1 million as of March 31, 2008.  The credit facility, through a series of amendments, includes commitments from: Wachovia Bank N.A.; Bank of Oklahoma; Allied Irish Banks p.l.c.; Guaranty Bank, FSB; Royal Bank of Canada; and The Royal Bank of Scotland, plc.  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.  We are required to pay a commitment fee of ..25% to .375% 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 ..375% and adjusted LIBOR borrowings are assessed an additional margin spread of 1.125% to 1.875%, based upon the outstanding balance under the credit facility.  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.

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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, (g) enter into transactions with our affiliates, (h) change the character of our business, (i) engage in hedging activities unless certain requirements are satisfied, (j) issue certain types of stock, and (k) make certain amendments to our organizational documents.  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, and (b) not to exceed a maximum leverage ratio.

As of March 31, 2008, our credit facility was undrawn compared to $235 million as of December 31, 2007.  The borrowing rate on the outstanding balance was 7.07% as of December 31, 2007.  Future amounts outstanding under the credit facility will be secured by substantially all of our properties.  We were in compliance with all covenants at March 31, 2008, and expect to remain in compliance throughout 2008.

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, commencing on August 15, 2008.  The senior notes were issued at a price of 98.572% of the principal amount.  In addition, we capitalized $5.4 million in costs associated with the issuance of the debt which 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.

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 incur additional debt; make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock; sell assets, including capital stock of our restricted subsidiaries; restrict dividends or other payments by restricted subsidiaries; create liens that secure debt; enter into transactions with affiliates; and merge or consolidate with another company.  We were in compliance with all covenants as of March 31, 2008, and expect to remain in compliance throughout 2008.

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.

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.

11


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.  If we fail to comply with certain obligations under the registration rights agreement, a situation that is not expected to occur, we will be required to pay liquidated damages to the holders of the notes in an amount equal to $.05 per week per $1,000 principal amount held by the holder for the first 90-day period immediately following the default.  The amount of the liquidated damages increases by an additional $.05 per week per $1,000 principal amount held by the holder with respect to each subsequent 90-day period until the default has been cured, up to a maximum amount of liquidated damages of $.20 per week per $1,000 principal amount held by the holder.  On April 24, 2008, we filed the related registration statement on Form S-4.  As of the date of this filing, the registration statement has not yet been declared effective.

7.  COMMITMENTS AND CONTINGENCIES

Drilling and Development Agreements.  We are a party to a pipeline expansion agreement with an unrelated third party, which is also currently the purchaser of the majority of our Wattenberg Field natural gas production.  Pursuant to the agreement, we have agreed to invest a minimum of $65 million to develop specified acreage in the Wattenberg Field, during a three-year period ending December 31, 2009.  Such capital spending will include costs to drill new wells and the cost to recomplete existing wells in this area.  Should we not meet the minimum commitment by December 31, 2009, we will be required to pay liquidated damages of $2 million, prorated based on our actual capital investment made to date.  As of March 31, 2008, our total capital expenditures pursuant to the agreement were $41.7 million, resulting in a maximum potential obligation for liquidating damages of $0.7 million.

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, 2008, no wells had been drilled pursuant to this agreement.

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, and subject to our financial ability to do so.  The maximum annual repurchase obligation as of March 31, 2008, was approximately $7 million.  We have adequate liquidity to meet this obligation.  During the first three months of 2008 and 2007, we paid $0.8 million and $1.6 million, respectively, under this provision for the repurchase of partnership units.

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.

Drilling Rig Contracts.  In order to secure the services for drilling rigs, we made commitments to the drilling contractors, which call for a minimum commitment of $12,500 daily for a specified amount of time if we cease to use the drilling rigs, an event that is not anticipated to occur, and a maximum commitment of $40,680 daily for a specified amount of time for daily use of the drilling rigs.  As of March 31, 2008, commitments for these two separate contracts expire in August 2009 and July 2010.  As of March 31, 2008, we have an outstanding minimum commitment for $6 million and an outstanding maximum commitment for $22.9 million.

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 and that the ultimate results of such proceedings, will not have a material adverse effect on our financial position or results of operations.

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 the State of Colorado (the "Droegemueller Action").  The plaintiff seeks 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, and on July 10, 2007, we filed our answer and affirmative defenses.  A second similar Colorado class action suit was filed against the Company in the U.S. District Court for the District of Colorado on December 3, 2007, by Ted Amsbaugh et al.  This case was consolidated with the Droegemueller Action above on January 28, 2008.  On February 29, 2008, the court approved a 90 day stay in proceedings while the parties pursue mediation of the matter.  Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, we are unable to predict the ultimate outcome of this suit at this time.  We believe that the ultimate outcome of the proceedings will not have a material adverse effect on our financial condition or results of operations.

12


Litigation similar to the preceding actions has been commenced against several other companies in other jurisdictions where we conduct business.  While our business model differs from that of the parties involved in such other litigation, and although the Company has not been named as a party in such other litigation, there can be no assurance that the Company will not be named as a party to such other litigation in the future.

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.

In the event of termination without cause or if an executive officer terminates employment for good reason, the executive officer is entitled to receive a payment in the amount of three times the sum of his highest base salary during the previous two years of employment immediately preceding the termination date and his highest bonus received during the same two year period.  The executive officer is also entitled to (i) vesting of any unvested equity compensation, (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 a pro rata bonus amount.  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.

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.

8.  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 and restricted stock.  Through the date of this report, we have not issued any stock appreciation rights.

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,
 
   
2008
   
2007
 
   
(in thousands)
 
             
Total stock-based compensation expense
  $ 1,792  (1)   $ 483  
Income tax benefit
    (691 )     (186 )
                 
Net income impact
  $ 1,101     $ 297  

______________
(1) Includes $1.1 million related to the separation agreement with our former president.

Stock Option Awards.  We granted stock options in previous years under several 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 option awards for the three months ended March 31, 2008 and 2007.

13


The following table provides a summary of our stock option award activity for the three months ended March 31, 2008:

   
Number of
Shares
Underlying
Options
   
Weighted
Average
Exercise
Price
Per Share
   
Weighted
Average
Remaining
Contractual
Term
(in years)
   
Aggregate
Intrinsic
Value
(in millions)
 
                         
Outstanding at December 31, 2007
    51,567     $ 33.55       6.4     $ 1.3  
Exercised
    (8,829 )     41.51               0.2  
Outstanding at March 31, 2008
    42,738       31.90       5.9       1.6  
                                 
Vested and expected to vest at March 31, 2008
    37,512       30.39       5.6       1.5  
                                 
Exercisable at March 31, 2008
    29,283       26.89       5.0       1.2  


Total unrecognized stock-based compensation cost related to stock options expected to vest was $0.1 million as of March 31, 2008.  This cost is expected to be recognized over a weighted average period of 1.5 years.  As of March 31, 2008, stock-based compensation related to stock options not expected to vest and unamortized was $0.1 million.

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.

The following table sets forth the changes in non-vested time-based awards for the three months ended March 31, 2008:

   
Shares
   
Weighted Average
Grant-Date
Fair Value
 
Non-vested at December 31, 2007
    171,845     $ 44.38  
Granted
    56,497       67.51  
Vested
    (26,507 )     50.36  
Forfeited
    (2,891 )     41.81  
Non-vested at March 31,  2008
    198,944     $ 51.04  


The total compensation cost related to non-vested time-based awards expected to vest and not yet recognized as of March 31, 2008, is $8.1 million.  This cost is expected to be recognized over a weighted-average period of 2.8 years.  As of March 31, 2008, stock-based compensation related to time-based awards not expected to vest and unamortized was $0.6 million.

 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.

14


The weighted average grant date fair value of each market-based share was computed using the Monte Carlo pricing model and the following weighted average assumptions:

 
Three Months Ended
 
March 31,
 
2008
 
2007
       
Expected term of award
3 years
 
3 years
Risk-free interest rate
2.4%
 
4.7%
Volatility
47.0%
 
44.0%


The following table sets forth the changes in non-vested marked-based awards for the three months ended March 31, 2008:

   
Shares
   
Weighted Average
Grant-Date
Fair Value
 
Non-vested at December 31, 2007
    31,972     $ 36.07  
Granted
    48,405       45.15  
Vested
    (3,078 )     52.00  
Forfeited
    (4,616 )     36.07  
Non-vested at March 31, 2008
    72,683     $ 43.64  

The total compensation cost related to non-vested market-based awards expected to vest and not yet recognized as of March 31, 2008, is $1.3 million.  This cost is expected to be recognized over a weighted-average period of 2.8 years.   As of March 31, 2008, stock-based compensation related to market-based awards not expected to vest and unamortized was $1.6 million.

9.  INCOME TAXES

We evaluate the estimated annual effective income tax rate on a quarterly basis based on current and forecasted business results and enacted tax laws.  This estimated annual effective tax rate is updated quarterly based upon actual results and updated operating forecasts.  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 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.

Our effective tax rate, inclusive of discrete items, was 37.1% for the first quarter of 2008, relatively unchanged from 36.5% for the first quarter of 2007.  Our rate differs from the combined federal and state statutory rates (net of the federal benefit), primarily due to certain business incentives such as percentage depletion and the domestic production deduction.  Discrete items were not significant.

As of March 31, 2008, we had a gross liability for uncertain tax benefits of $0.9 million, of which $0.4 million, if recognized, would affect our effective tax rate.  There were no significant changes to the calculation since year end 2007.

The Internal Revenue Service ("IRS") has begun its examination of our 2005 and 2006 tax years, and we currently expect this examination to be completed within one year.  Therefore, we expect the amount noted above, that is accrued for uncertain tax benefits in our current tax liability on our balance sheet, to be reduced during the next year.

Our Michigan Single Business Tax returns for the tax years 2002 through 2006 are currently under examination by the Michigan Department of Treasury.  No significant tax adjustments have been proposed and none are currently expected.  We are current with our income tax filings in other state jurisdictions and currently have no other state income tax returns in the process of examination or administrative appeal.

15


10.  EARNINGS PER SHARE

A reconciliation of basic and diluted earnings per common share is as follows:

   
Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands, except per share data)
 
             
Weighted average common shares outstanding
    14,738       14,726  
Dilutive effect of share-based compensation: (1)
               
Unamortized portion of restricted stock
    -       63  
Stock options
    -       60  
Non employee director deferred compensation
    -       5  
Weighted average common and common equivalent shares outstanding
    14,738       14,854  
                 
Net income (loss)
  $ (13,928 )   $ 2,501  
Basic earnings (loss) per common share
  $ (0.95 )   $ 0.17  
Diluted earnings (loss) per common share
  $ (0.95 )   $ 0.17  


(1) For the three months ended March 31, 2008, 70, 38 and 6 average common share equivalents related to unvested restricted stock, stock options and shares related to non employee director deferred compensation, respectively, were excluded from the computation of diluted net loss per share as their effect was anti-dilutive.  For the three months ended March 31, 2007, there were no common share equivalents excluded from the computation of diluted net income per share.

11.  BUSINESS SEGMENTS

Our operating activities can be divided into four major segments: oil and gas sales, natural gas marketing, oil and gas well drilling operations, and well operations and pipeline income.  We drill natural gas wells for Company-sponsored drilling partnerships and retain an interest in each well.  A wholly-owned subsidiary, Riley Natural Gas, engages in the marketing of natural gas to commercial and industrial end-users.  We own an interest in approximately 4,400 wells from which we sell our oil and gas production from our working interests in the wells.  We charge Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering.  All material inter-company accounts and transactions between segments have been eliminated.  Segment information for the three months ended March 31, 2008 and 2007 is presented below.

   
Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Revenues:
           
Oil and gas sales (1)
  $ 29,336     $ 28,371  
Natural gas marketing
    23,325       21,987  
Oil and gas well drilling operations
    3,083       4,030  
Well operations and pipeline income
    2,352       3,298  
Unallocated amounts
    3       226  
Total
  $ 58,099     $ 57,912  
                 
Segment income (loss) before income taxes:
               
Oil and gas sales (1)(2)
  $ (11,994 )   $ 5,839  
Natural gas marketing
    1,332       679  
Oil and gas well drilling operations
    3,005       3,467  
Well operations and pipeline income (3)
    592       1,234  
Unallocated amounts (4)
    (15,065 )     (7,282 )
Total
  $ (22,130 )   $ 3,937  
 
16


 
_______________
(1)
Includes oil and gas price risk management loss, net of $42.3 million and $5.6 million for the three months ended March 31, 2008 and 2007, respectively.
(2)
Includes $4.3 million and $2.7 million in exploration costs and $20.3 million and $12.4 million of DD&A expense for the three months ended March 31, 2008 and 2007, respectively.
(3)
Includes $0.4 million and $0.5 million of DD&A expense for the three months ended March 31, 2008 and 2007, respectively.
(4)
Includes general and administrative expense, interest income, interest expense, and DD&A expense of $0.5 million and $0.2 million for the three months ended March 31, 2008 and 2007, respectively.


   
March 31,
   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Segment assets:
           
Oil & gas sales
  $ 882,469     $ 862,237  
Natural gas marketing
    39,543       40,269  
Oil and gas well drilling operations
    8,233       4,959  
Well operations and pipeline income
    54,814       26,156  
Unallocated amounts
    90,408       116,858  
Total
  $ 1,075,467     $ 1,050,479  
 

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

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This current report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements.  These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.  Among those risks, trends and uncertainties are our estimates of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in successfully drilling productive wells and in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, our ability to sell our produced natural gas and oil and the prices we receive for  production, our ability to control the costs of our operations, our ability to comply with changes in federal, state, local, and other laws and regulations, including environmental policies, and the operating hazards attendant to the oil and natural gas business.  In particular, careful consideration should be given to cautionary statements made in this Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2007, and our other SEC filings and public disclosures.  We undertake no duty to update or revise these forward-looking statements.

Management Overview

Net loss for the three months ended March 31, 2008, was $13.9 million compared to net income of $2.5 million for the same prior year period.  The primary reason for the loss during the first quarter of 2008 compared to 2007 was due to the unrealized losses on derivatives of $39.9 million compared to $6.2 million for the same prior year period.  Rapid increases during the first quarter of 2008 to record high oil prices and sharp increases in natural gas prices from December 31, 2007, to March 31, 2008, along with our increased use of derivative contracts and specifically more fixed price swaps caused the increase in realized and unrealized losses in oil and gas price risk management loss, net.  See Oil and Gas Price Risk Management Loss, Net discussion below for a detailed discussion of realized and unrealized losses on oil and gas derivative activity.  The major offsetting factors, which somewhat mitigated the non-cash unrealized derivative loss, were the effect on oil and gas sales due to significantly increased production and commodity prices realized during the period.

Our total oil and natural gas production increased by 3.1 Bcfe or approximately 59% during the quarter ended March 31, 2008, compared to the quarter ended March 31, 2007.  During this same time period, the average sales price per Mcfe increased by approximately 32% from $6.38 per Mcfe during the quarter ended March 31, 2007, to $8.45 per Mcfe during the quarter ended March 31, 2008.  See our oil and gas production table below under Oil and Gas Sales.

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Total revenues for the three months ended March 31, 2008, were $58.1 million compared to $57.9 million for the same prior year period.  The two offsetting items for the quarter ended March 31, 2008, compared with 2007 were oil and gas sales and oil and gas price risk management loss, net.  Our total oil and gas sales increased from $34 million for the three months ended March 31, 2007, to $71.6 million for the three months ended March 31, 2008, an increase of $37.6 million or 111%.  The increase was driven by an increase in production of 59% and an increase in realized oil and natural gas prices of 32%.

The $37.6 million increase in oil and gas sales was almost entirely offset by an increase in oil and gas price risk management loss, net of $36.7 million for the three months ended March 31, 2008, compared with the prior year first quarter.  Of the $42.3 million oil and gas price risk management loss for the first quarter of 2008, $39.9 million resulted from non-cash unrealized losses resulting from significant increases in oil and gas commodity prices from December 31, 2007, to March 31, 2008, on open derivative positions.

Costs and expenses for the three months ended March 31, 2008, were $75.6 million compared to $54.3 million for the same prior year period, an increase of $21.3 million or 39.2%.  The increase was primarily the result of increases in oil and gas production and well operations cost, general and administrative expense and depreciation, depletion and amortization.

The 59% or 3.1 Bcfe increase in production for the first quarter of 2008 compared to the same prior year period was the primary contributor to the increases in oil and gas production and well operations cost and depreciation, depletion and amortization.  The increase in general and administrative expense is primarily due to expenses associated with the separation agreement executed with our former president upon his resignation.

While we benefit significantly from the rising energy prices in our oil and gas sales, the rising energy prices bring about inflationary factors that affect our costs and expenses.  The increase in energy prices has affected demand for drilling and completion services, land acquisitions, and the cost of experienced industry personnel.  The cost of steel used for tubular goods and surface equipment has increased dramatically over the past several years and represents approximately 20% to 30% of the total cost of a new well.  We expect this inflationary trend to continue as energy prices rise.  We consume great quantities of fuel in the use of drilling rigs, service rigs, vehicles used for hauling materials, such as surface casing, tubular goods and water, as well as, vehicles used for well tending and general operations.  

See the following discussion of results of operations describing in more detail the components of revenues and expenses and, where significant, providing an analysis of changes year over year and the cause or underlying reason for such change.

Results of Operations

Revenues

Oil and Gas Sales

   
Three Months Ended March 31,
   
Change
 
   
2008
   
2007
   
Amount
   
Percent
 
   
(dollars in thousands)
 
                         
Oil and gas sales
  $ 71,646     $ 34,016     $ 37,630       110.6 %


Oil and gas sales from our producing properties for the three months ended March 31, 2008, were $71.6 million compared to $34.0 million for the same prior year period, an increase of $37.6 million or approximately 111%.  The increase was due to increased volumes of natural gas and oil along with increased average sales prices of natural gas and oil.

Increased volumes of oil and natural gas produced contributed $25.1 million to oil and gas sales revenue for the current quarter and significantly increased commodity prices contributed the remaining $12.5 million increase in oil and gas sales revenue, for a total increase in oil and natural gas sales revenue of $37.6 million for the first quarter of 2008 compared to the same prior year period.  The volume of natural gas sold for the three months ended March 31, 2008, was 6.9 Bcf at an average sales price of $7.33 per Mcf compared to 4.1 Bcf at an average sales price of $6.05 per Mcf for the three months ended March 31, 2007.  Oil sales were 255,500 barrels at an average sales price of $81.14 per barrel for the three months ended March 31, 2008, compared to 199,500 barrels at an average sales price of $45.06 per barrel for the three months ended March 31, 2007.  The increase in oil and natural gas volumes resulted from acquisitions of producing oil and gas properties and a significant increase in the number of wells drilled for our own account over the past year.

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Oil and Gas Production.  Our oil and natural gas production by area of operations along with average sales price (excluding derivative gains/losses) is presented below:
 
   
Three Months Ended March 31,
                   
   
2008
   
2007
   
Change
 
   
Oil
(Bbls)
   
Natural Gas
(Mcf)
   
Natural Gas Equivalent
(Mcfe)
   
Oil
(Bbls)
   
Natural Gas
(Mcf)
   
Natural Gas Equivalent
(Mcfe)
   
Oil
   
Natural
Gas
   
Total
 
Production
                                                     
Appalachian Basin
    1,096       967,620       974,196       1,374       609,397       617,641       -20 %     59 %     58 %
Michigan Basin
    823       379,437       384,375       815       420,887       425,777       1 %     -10 %     -10 %
Rocky Mountain Region
    253,533       5,599,765       7,120,963       197,350       3,105,669       4,289,769       28 %     80 %     66 %
Total
    255,452       6,946,822       8,479,534       199,539       4,135,953       5,333,187       28 %     68 %     59 %
                                                                         
   
Three Months Ended March 31,
                         
   
2008
   
2007
   
Change
 
   
Oil
   
Natural
Gas
   
Total
   
Oil
   
Natural
Gas
   
Total
   
Oil
   
Natural
Gas
   
Total
 
   
(dollars in thousands, except average price)
                         
Sales
                                                                       
Appalachian Basin
  $ 97     $ 8,138     $ 8,235     $ 69     $ 4,052     $ 4,121       41 %     101 %     100 %
Michigan Basin
    79       2,895       2,974       40       2,568       2,608       98 %     13 %     14 %
Rocky Mountain Region
    20,551       39,886       60,437       8,882       18,408       27,290       131 %     117 %     121 %
Total
  $ 20,727     $ 50,919     $ 71,646     $ 8,991     $ 25,028     $ 34,019       131 %     103 %     111 %
                                                                         
Average Sales Price
                                                                       
(Oil - per Bbl, Natural Gas - per Mcf, Total - per Mcfe)
                                                                 
Appalachian Basin
  $ 88.71     $ 8.41     $ 8.45     $ 50.59     $ 6.65     $ 6.67       75 %     26 %     27 %
Michigan Basin
    96.03       7.63       7.74       49.02       6.10       6.12       96 %     25 %     26 %
Rocky Mountain Region
    81.08       7.13       8.49       45.02       5.92       6.36       80 %     20 %     33 %
Total
  $ 81.14     $ 7.33     $ 8.45     $ 45.06     $ 6.05     $ 6.38       80 %     21 %     32 %


Late in June 2007, we placed into service the upgraded Garden Gulch pipeline and compressor facility, which serves a majority of our wells in the Piceance Basin of our Rocky Mountain Region.  This upgrade included two new natural gas compressors, with a third compressor added in the third quarter, and pipeline facility enhancements.  The upgrade and enhancements have increased the capacity of the pipeline delivery system from 17,000 Mcf per day to 60,000 Mcf per day from our wells feeding this facility.

Oil and Gas Pricing. Financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production effectively.  Natural gas and oil 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.  Such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline capacity to non-local markets.  The result, beginning in the second quarter of 2007 and continuing into the fourth quarter of 2007, was a decrease in the price of Rocky Mountain natural gas compared to the New York Mercantile Exchange ("NYMEX") price and other markets as shown in the graph below.  The expansion in January 2008 of the Rockies Express pipeline, a major interstate pipeline constructed and operated by a non-affiliated entity, is the primary reason for the narrowing of the NYMEX/Colorado Interstate Gas ("CIG") gap from November 2007 and forward.  Once the third phase of the expansion of the Rockies Express is completed in 2009, the pipeline capacity is expected to increase by 64% to 1.8 Bcf/per day of natural gas from the region.  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.  In the Rocky Mountain Region in 2007, and the first quarter of 2008, the oil prices we received were below the NYMEX oil market due to supply competition from Rocky Mountain and Canadian oil that has driven down market prices.  Beginning in the middle of the second quarter of 2008, through the end of 2010, we have contracted the majority of our oil sales at a price with a smaller spread below NYMEX.

Rocky Mountain Region Pricing.  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 may include some gas sold at the CIG 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.

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The graph below identifies the actual NYMEX and CIG natural gas prices by month from January 2006 through April 2008 and the forward curve for natural gas prices from May 2008 through November 2009 as of April 21, 2008.  The forecasted prices in the graph have been derived from the sources indicated and represent, in our opinion, a reasonable view of the possible movement of the CIG and NYMEX natural gas prices over the next nineteen months.  However, because the prices given in the graph represent forecasts of future matters and are subject to future events which we cannot predict, we can give no assurance that these forecasted prices will be as they are presented in the graph.  An investor should therefore not rely on these forecasted prices in making an investment decision regarding our stock.

______________
*Source:  Derived from various sources including FutureSource, Inside Federal Energy Regulatory Commission's ("FERC") Gas Market Report and ClearPort Trading.

While the above graph shows a large differential between 2007 NYMEX and CIG pricing, the gap began narrowing in November 2007 and has continued to narrow.  As of April 21, 2008, the negative price differential between NYMEX and CIG for 2008 has narrowed to $1.93 from $3.38 average for the fourth quarter of 2007.  Although 80.6% of our first quarter 2008 natural gas production came from the Rocky Mountain Region, 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 pricing for sales volumes during the quarter ended March 31, 2008.  The pricing basis is the index that most closely relates to the contract under which the oil and natural gas is sold.  As it indicates, 40% of our natural gas sales are derived from the CIG Index and other similarly priced Rocky Mountain pipelines.

Energy Market Exposure
For the Three Months Ended March 31, 2008
Area
 
Pricing Basis
 
Commodity
 
Percent of
 Oil and Gas
Sales
             
Piceance/Wattenberg
 
Rocky Mountain (CIG, et. al.)
 
Gas
 
40.0%
NECO
 
Mid Continent (Panhandle Eastern)
 
Gas
 
26.0%
Colorado/North Dakota
 
NYMEX
 
Oil
 
16.0%
Appalachian
 
NYMEX
 
Gas
 
11.0%
Michigan
 
Mich-Con/NYMEX
 
Gas
 
5.0%
Wattenberg
 
Colorado Liquids
 
Gas
 
2.0%
           
100.0%
 
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Natural Gas Marketing Activities

   
Three Months Ended March 31,
   
Change
 
   
2008
   
2007
   
Amount
   
Percent
 
   
(dollars in thousands)
 
                         
Sales from natural gas marketing activities
    23,325       21,987       1,338       6.1 %


The increase in sales from natural gas marketing activities in 2008 is primarily due to an increase in prices and volumes sold, partially offset by a $4.3 million increase in unrealized losses on derivative transactions from a $3.3 million loss in 2007 to a $7.6 million loss in 2008.

Our natural gas marketing segment specializes in the purchase, aggregation and sale of natural gas production in our eastern operating areas.  Through our natural gas marketing segment, we market the natural gas we produce as well as our purchases of natural gas from other producers in the Appalachian Basin, including our affiliated partnerships.  Our derivative activities related to natural gas marketing activities include both physical and cash-settled derivatives.  We offer fixed-price derivative contracts for the purchase or sale of physical gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions.  We do not take speculative positions on commodity prices.

Oil and Gas Price Risk Management Loss, Net

   
Three Months Ended March 31,
   
Change
 
   
2008
   
2007
   
Amount
   
Percent
 
   
(dollars in thousands)
 
Oil and gas price risk management:
                       
Realized gain (loss):
                       
Oil
  $ (1,306 )   $ (52 )   $ (1,254 )    
*
 
Natural gas
    (1,105 )     632       (1,737 )    
*
 
Total realized gain (loss)
    (2,411 )     580       (2,991 )    
*
 
Unrealized loss
    (39,899 )     (6,225 )     (33,674 )    
*
 
Oil and gas price risk management loss, net
  $ (42,310 )   $ (5,645 )   $ (36,665 )    
*
 

______________
*Represents percentages in excess of 250%.

The rapid increases during the first quarter of 2008 to record high oil prices and sharp increases in natural gas prices from December 31, 2007, to March 31, 2008, along with our increased use of derivative contracts and specifically more fixed price swaps caused the increase in realized and unrealized losses in oil and gas price risk management loss, net.  The $39.9 million in unrealized losses for the three months ended March 31, 2008, is the fair value of the derivative positions as of March 31, 2008, less the fair value as of December 31, 2007, and includes all open positions as of March 31, 2008, for the entire period from April 2008 until the expiration of the last position, which is February 2011.  The unrealized loss is a non-cash item in the first quarter of 2008 and there will be further gains or losses as prices increase or decrease until the positions are closed.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 results in significant swings in value and resulting gains and losses for reporting purposes 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.

Oil and gas price risk management loss, net includes realized gains and losses and unrealized changes in the fair value of oil and natural gas derivatives related to our oil and natural gas production.  Oil and gas price risk management loss, net does not include commodity based derivative transactions related to transactions from natural gas marketing activities, which are included in sales from and cost of natural gas marketing activities.  See Notes 4 and 5 to the accompanying condensed consolidated financial statements for additional details of our derivative financial instruments.

Oil and Gas Derivative Activities.  Because of uncertainty surrounding oil and natural gas prices we have used various derivative instruments to manage some of the impact of fluctuations in prices.  Through February 2011, we have in place a series of floors, ceilings, collars and fixed price swaps on a portion of our oil and natural gas production.  Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor, the counterparty pays us.  During the three months ended March 31, 2008, we averaged natural gas volumes sold of 2.3 Bcf per month and oil sales of 85,000 barrels per month.

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The following table sets forth our derivative positions in effect as of  May 12, 2008, on our share of production by area.
 
             
Floors
   
Ceilings
   
Swaps (Fixed Prices)
 
Commodity/
Index/
Area
Month Set
Month
 
Gross
Monthly Quantity
Gas -MMbtu
Oil -Bbls
   
Net
Monthly Quantity
Gas -MMbtu
Oil -Bbls
   
Floor
Price
   
Net
Monthly Quantity
Gas -MMbtu
Oil -Bbls
   
Ceiling
Price
   
Net
Monthly Quantity
Gas-MMbtu
Oil -Bbls
   
Price
 
Natural Gas - Colorado Interstate Gas (CIG) Based Derivatives
 
Piceance Basin
 
                                         
 
Feb-08
Apr 08 - Oct 08
    750,000       -     $ -       -     $ -       454,650     $ 7.05  
 
Jan-08
Apr 08 - Oct 08
    630,000       -       -       -       -       381,906       6.54  
 
Apr-08
Nov 08 - Mar 09
    570,000       -       -       -       -       345,534       7.76  
 
Feb-08
Nov 08 - Mar 09
    340,000       206,108       7.00       206,108       9.70       -       -  
 
Feb-08
Nov 08 - Mar 09
    340,000       -       -       -       -       206,108       8.18  
 
Jan-08
Apr 09 - Oct 09
    570,000       345,534       5.75       345,534       8.75       -       -  
 
Mar-08
Apr 09 - Oct 09
    560,000       339,472       5.75       339,472       9.05       -       -  
                                                             
Wattenberg Field
                                                         
 
Feb-08
Apr 08 - Oct 08
    450,000       -       -       -       -       321,480       7.05  
 
Jan-08
Apr 08 - Oct 08
    290,000       -       -       -       -       211,460       6.54  
 
Apr-08
Nov 08 - Mar 09
    320,000       -       -       -       -       241,460       7.76  
 
Feb-08
Nov 08 - Mar 09
    180,000       133,590       7.00       133,590       9.70       -       -  
 
Feb-08
Nov 08 - Mar 09
    180,000       -       -       -       -       133,590       8.18  
 
Jan-08
Apr 09 - Oct 09
    320,000       241,460       5.75       241,460       8.75       -       -  
 
Mar-08
Apr 09 - Oct 09
    290,000       218,600       5.75       218,600       9.05       -       -  
                                                             
Natural Gas - Panhandle Based Derivatives
                                                       
NECO
                                                           
 
Feb-08
Apr 08 - Oct 08
    180,000       -       -       -       -       180,000       7.45  
 
Jan-08
Apr 08 - Oct 08
    120,000       -       -       -       -       120,000       6.80  
 
Apr-08
Nov 08 - Mar 09
    110,000       -       -       -       -     &#