Attached files

file filename
EX-31.1 - EX-31.1 - PAR PETROLEUM CORP/COd77554exv31w1.htm
EX-32.1 - EX-32.1 - PAR PETROLEUM CORP/COd77554exv32w1.htm
EX-32.2 - EX-32.2 - PAR PETROLEUM CORP/COd77554exv32w2.htm
EX-31.2 - EX-31.2 - PAR PETROLEUM CORP/COd77554exv31w2.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2010
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 0-16203
(DELTA LOGO)
DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of incorporation or organization)
  84-1060803
(I.R.S. Employer Identification No.)
     
370 17th Street, Suite 4300
Denver, Colorado
(Address of principal executive offices)
 
80202
(Zip Code)
(303) 293-9133
(Registrant’s telephone number, including area code)
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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 þ   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes o No þ
285,216,209 shares of common stock, $.01 par value per share, were outstanding as of November 1, 2010.
 
 

 


 

INDEX
         
    Page No.
PART I FINANCIAL INFORMATION
 
       
Item 1. Consolidated Financial Statements
 
       
    1  
 
       
    2  
 
       
    3  
 
       
    4  
 
       
    5  
 
       
    6  
 
       
    33  
 
       
    51  
 
       
    52  
 
       
       
 
       
    52  
 
       
    53  
 
       
    53  
 
       
    53  
 
       
    54  
The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its consolidated entities unless the context suggests otherwise.

I


Table of Contents

PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
 
                 
    September 30,     December 31,  
    2010     2009  
    (In thousands, except share data)  
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 14,197     $ 61,918  
Short-term restricted deposits
    100,000       100,000  
Trade accounts receivable, net of allowance for doubtful accounts of $2,348 and $100, respectively
    15,594       16,654  
Property sale purchase price receivable
    17,750        
Deposits and prepaid assets
    945       3,103  
Inventories
    3,965       5,588  
Derivative instruments
    1,165        
Other current assets
    3,385       5,189  
 
           
Total current assets
    157,001       192,452  
 
               
Property and equipment:
               
Oil and gas properties, successful efforts method of accounting:
               
Unproved
    235,612       280,844  
Proved
    867,036       1,379,920  
Drilling and trucking equipment
    174,445       177,762  
Pipeline and gathering systems
    97,696       92,064  
Other
    15,573       16,154  
 
           
Total property and equipment
    1,390,362       1,946,744  
Less accumulated depreciation and depletion
    (512,677 )     (800,501 )
 
           
Net property and equipment
    877,685       1,146,243  
 
           
 
               
Long-term assets:
               
Long-term restricted deposit
    100,000       100,000  
Investments in unconsolidated affiliates
    3,208       7,444  
Deferred financing costs
    2,109       3,017  
Other long-term assets
    6,352       8,329  
 
           
Total long-term assets
    111,669       118,790  
 
           
 
               
Total assets
  $ 1,146,355     $ 1,457,485  
 
           
                 
LIABILITIES AND EQUITY
Current liabilities:
               
Credit facility — Delta
  $ 21,500     $  
Credit facility — DHS
    71,590       83,268  
Installment payable on property acquisition
    99,785       97,874  
Accounts payable
    32,410       44,225  
Offshore litigation payable
          13,877  
Other accrued liabilities
    17,510       13,459  
Derivative instruments
          19,497  
 
           
Total current liabilities
    242,795       272,200  
 
               
Long-term liabilities:
               
Installment payable on property acquisition, net of current portion
    97,244       95,381  
7% Senior notes
    149,666       149,609  
33/4% Senior convertible notes
    107,431       104,008  
Credit facility — Delta
          124,038  
Asset retirement obligations
    3,942       7,654  
Derivative instruments
    65       7,475  
 
           
Total long-term liabilities
    358,348       488,165  
 
               
Commitments and contingencies
               
 
               
Equity:
               
Preferred stock, $.01 par value:
               
authorized 3,000,000 shares, none issued
           
Common stock, $.01 par value: authorized 600,000,000 shares, issued 285,637,000 shares at September 30, 2010 and 282,548,000 shares at December 31, 2009
    2,856       2,825  
Additional paid-in capital
    1,630,357       1,625,035  
Treasury stock at cost; 33,000 shares at September 30, 2010 and 42,000 shares at December 31, 2009
    (31 )     (268 )
Accumulated deficit
    (1,087,616 )     (939,010 )
 
           
Total Delta stockholders’ equity
    545,566       688,582  
 
           
Non-controlling interest
    (354 )     8,538  
 
           
Total equity
    545,212       697,120  
 
           
 
               
Total liabilities and equity
  $ 1,146,355     $ 1,457,485  
 
           
See accompanying notes to consolidated financial statements.

1


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
                 
    Three Months Ended  
    September 30,  
    2010     2009  
    (In thousands, except per share amounts)  
Revenue:
               
 
               
Oil and gas sales
  $ 20,233     $ 19,059  
Contract drilling and trucking fees
    15,204       2,538  
Loss on offshore litigation award and property sales, net
    (1 )     (150 )
 
           
 
               
Total revenue
    35,436       21,447  
 
           
 
               
Operating expenses:
               
 
               
Lease operating expense
    5,969       6,809  
Transportation expense
    3,388       2,028  
Production taxes
    996       717  
Exploration expense
    368       891  
Dry hole costs and impairments
    (262 )     53,407  
Depreciation, depletion, amortization and accretion — oil and gas
    14,410       20,065  
Drilling and trucking operating expenses
    12,041       2,818  
Depreciation and amortization — drilling and trucking
    4,801       5,545  
General and administrative
    10,345       9,953  
Executive severance expense, net
    (674 )      
 
           
 
               
Total operating expenses
    51,382       102,233  
 
           
 
               
Operating loss
    (15,946 )     (80,786 )
 
           
 
               
Other income and (expense):
               
 
               
Interest expense and financing costs, net
    (9,310 )     (9,706 )
Other income (expense), net
    (36 )     220  
Realized gain (loss) on derivative instruments, net
    (418 )     370  
Unrealized gain (loss) on derivative instruments, net
    7,124       (5,923 )
Loss from unconsolidated affiliates
    (90 )     (454 )
 
           
 
               
Total other expense
    (2,730 )     (15,493 )
 
           
 
               
Loss from continuing operations before income taxes and discontinued operations
    (18,676 )     (96,279 )
 
               
Income tax expense
    86       265  
 
           
 
               
Loss from continuing operations
    (18,762 )     (96,544 )
 
               
Discontinued operations:
               
 
               
Income (loss) from results of operations and sale of discontinued operations, net of tax
    29,495       (4,429 )
 
           
 
               
Net income (loss)
    10,733       (100,973 )
 
               
Less net loss attributable to non-controlling interest
    3,209       4,146  
 
           
 
               
Net income (loss) attributable to Delta common stockholders
  $ 13,942     $ (96,827 )
 
           
 
               
Amounts attributable to Delta common stockholders:
               
Loss from continuing operations
  $ (15,553 )   $ (92,398 )
Income (loss) from discontinued operations, net of tax
    29,495       (4,429 )
 
           
Net income (loss)
  $ 13,942     $ (96,827 )
 
           
 
               
Basic income (loss) attributable to Delta common stockholders per common share:
               
Loss from continuing operations
  $ (0.06 )   $ (0.34 )
Discontinued operations
    0.11       (0.01 )
 
           
Net income (loss)
  $ 0.05     $ (0.35 )
 
           
 
               
Diluted income (loss) attributable to Delta common stockholders per common share:
               
Loss from continuing operations
  $ (0.05 )   $ (0.34 )
Discontinued operations
    0.10       (0.01 )
 
           
Net income (loss)
  $ 0.05     $ (0.35 )
 
           
See accompanying notes to consolidated financial statements.

2


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
                 
    Nine Months Ended  
    September 30,  
    2010     2009  
    (In thousands, except per share amounts)  
Revenue:
               
 
               
Oil and gas sales
  $ 74,734     $ 56,786  
Contract drilling and trucking fees
    36,200       9,425  
Gain (loss) on offshore litigation award and property sales, net
    (539 )     31,054  
 
           
 
               
Total revenue
    110,395       97,265  
 
           
 
               
Operating expenses:
               
 
               
Lease operating expense
    20,903       21,273  
Transportation expense
    11,195       6,653  
Production taxes
    3,760       3,217  
Exploration expense
    952       2,422  
Dry hole costs and impairments
    30,859       161,471  
Depreciation, depletion, amortization and accretion — oil and gas
    45,540       62,992  
Drilling and trucking operating expenses
    28,053       10,416  
Depreciation and amortization — drilling and trucking
    15,599       17,512  
General and administrative
    33,372       31,545  
Executive severance expense, net
    (674 )     3,739  
 
           
 
               
Total operating expenses
    189,559       321,240  
 
           
 
               
Operating loss
    (79,164 )     (223,975 )
 
           
 
               
Other income and (expense):
               
 
               
Interest expense and financing costs, net
    (29,426 )     (41,907 )
Other income (expense), net
    (207 )     1,630  
Realized gain (loss) on derivative instruments, net
    (5,132 )     370  
Unrealized gain (loss) on derivative instruments, net
    28,072       (27,034 )
Income (loss) from unconsolidated affiliates
    893       (3,324 )
 
           
 
               
Total other expense
    (5,800 )     (70,265 )
 
           
 
               
Loss from continuing operations before income taxes and discontinued operations
    (84,964 )     (294,240 )
 
               
Income tax expense (benefit)
    564       (53 )
 
           
 
               
Loss from continuing operations
    (85,528 )     (294,187 )
 
               
Discontinued operations:
               
 
               
Loss from results of operations and sale of discontinued operations, net of tax
    (72,212 )     (16,702 )
 
           
 
               
Net loss
    (157,740 )     (310,889 )
 
               
Less net loss attributable to non-controlling interest
    9,134       16,191  
 
           
 
               
Net loss attributable to Delta common stockholders
  $ (148,606 )   $ (294,698 )
 
           
 
               
Amounts attributable to Delta common stockholders:
               
Loss from continuing operations
  $ (76,394 )   $ (277,996 )
Loss from discontinued operations, net of tax
    (72,212 )     (16,702 )
 
           
Net loss
  $ (148,606 )   $ (294,698 )
 
           
 
               
Basic income (loss) attributable to Delta common stockholders per common share:
               
Loss from continuing operations
  $ (0.28 )   $ (1.47 )
Discontinued operations
    (0.26 )     (0.08 )
 
           
Net loss
  $ (0.54 )   $ (1.55 )
 
           
 
               
Diluted income (loss) attributable to Delta common stockholders per common share:
               
Loss from continuing operations
  $ (0.28 )   $ (1.47 )
Discontinued operations
    (0.26 )     (0.08 )
 
           
Net loss
  $ (0.54 )   $ (1.55 )
 
           
See accompanying notes to consolidated financial statements.

3


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
 
                                                                         
                    Additional                   Accu-   Total Delta   Non-    
    Common stock   paid-in   Treasury stock   mulated   stockholders’   controlling   Total
    Shares   Amount   capital   Shares   Amount   deficit   equity   interest   equity
    (In thousands)
Balance, December 31, 2009
    282,548     $ 2,825     $ 1,625,035       42     $ (268 )   $ (939,010 )   $ 688,582     $ 8,538     $ 697,120  
 
                                                                       
Net loss
                                  (148,606 )     (148,606 )     (9,134 )     (157,740 )
Employee vesting of treasury stock held by subsidiary
                      (13 )     194             194       (194 )      
Issuance of vested stock
    5,653       56       (56 )                                    
Shares repurchased for withholding taxes
    (911 )     (9 )     (736 )     4       43             (702 )           (702 )
Forfeiture of restricted shares
    (1,653 )     (16 )     16                                      
Executive severance — stock-based awards forfeited
                (2,274 )                       (2,274 )           (2,274 )
Stock based compensation
                8,372                         8,372       436       8,808  
     
 
                                                                       
Balance, September 30, 2010
    285,637     $ 2,856     $ 1,630,357       33     $ (31 )   $ (1,087,616 )   $ 545,566     $ (354 )   $ 545,212  
     
See accompanying notes to consolidated financial statements.

4


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
                 
    Nine Months Ended  
    September 30,  
    2010     2009  
    (In thousands)  
Cash flows from operating activities:
               
Net loss
  $ (157,740 )   $ (310,889 )
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
               
Basis in offshore properties recovered through litigation
          17,647  
Loss on property sales
             
(Gain) loss on sale of drilling rig
          (1,663 )
Depreciation, depletion, amortization and accretion — oil and gas
    45,540       62,992  
Depreciation and amortization — drilling and trucking
    15,599       17,512  
Depreciation, depletion, amortization and accretion — discontinued operations
    13,837       19,477  
Stock based compensation
    8,808       7,433  
Executive severance payable in common stock
          1,700  
Executive severance — stock-based awards forfeited
    (2,274 )     (2,820 )
Amortization of deferred financing costs
    7,156       10,029  
Accretion of discount on installments payable
    3,774       5,582  
Increase in allowance for bad debt
    1,437        
Unrealized (gain) loss on derivative instruments, net
    (28,072 )     27,034  
Dry hole costs and impairments
    30,859       161,471  
Impairments — discontinued operations
    92,162        
Gain on sale of discontinued operations
    (28,372 )      
Loss on sale of drilling, trucking and other assets
    786        
(Income) loss from unconsolidated affiliates
    (893 )     3,660  
Deferred income tax expense (benefit)
    564       (53 )
Other
    43       (66 )
Net changes in operating assets and liabilities:
               
(Increase) decrease in trade accounts receivable
    (318 )     16,869  
Decrease in deposits and prepaid assets
    (242 )     3,638  
Increase in inventories
          (655 )
(Increase) decrease in other current assets
    919       (2,576 )
Decrease in accounts payable
    (20,627 )     (18,751 )
Increase (decrease) in other accrued liabilities and offshore litigation payable
    (8,904 )     2,588  
 
           
 
               
Net cash provided by (used in) operating activities
    (25,958 )     20,159  
 
           
 
               
Cash flows from investing activities:
               
Additions to property and equipment
    (24,959 )     (143,675 )
Additions to drilling and trucking equipment
    (1,322 )     (1,648 )
Proceeds from sale of oil and gas properties
    115,180        
Proceeds from sale of drilling assets and other fixed assets
    601       8,247  
Proceeds from sale of unconsolidated affiliate
    3,879        
Investment in unconsolidated affiliates
          295  
Proceeds from escrow deposit
    1,380        
(Increase) decrease in other long-term assets
    81       (419 )
 
           
 
               
Net cash provided by (used in) investing activities
    94,840       (137,200 )
 
           
 
               
Cash flows from financing activities:
               
Proceeds from borrowings
    86,500       77,000  
Repayments of borrowings
    (200,716 )     (259,017 )
Payment of deferred financing costs
    (1,641 )     (2,272 )
Proceeds from sale of offshore litigation contingent payment rights
          25,000  
Repurchase of offshore litigation contingent payment rights
          (25,000 )
Stock issued for cash, net
          246,918  
Shares repurchased for withholding taxes
    (746 )     (380 )
 
           
 
               
Net cash provided by (used in) financing activities
    (116,603 )     62,249  
 
           
 
               
Net decrease in cash and cash equivalents
    (47,721 )     (54,792 )
 
               
Cash at beginning of period
    61,918       65,475  
 
           
 
               
Cash at end of period
  $ 14,197     $ 10,683  
 
           
 
               
Supplemental cash flow information:
               
Cash paid for interest and financing costs
  $ 17,177     $ 27,607  
 
           
See accompanying notes to consolidated financial statements.

5


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(1) Nature of Organization and Basis of Presentation
Delta Petroleum Corporation (“Delta”), a Delaware corporation, and its consolidated subsidiaries (collectively, the “Company”) are principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company’s core area of operations is the Rocky Mountain Region in which the majority of its proved reserves, production and long-term growth prospects are concentrated.
The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, in accordance with those rules, do not include all the information and notes required by generally accepted accounting principles for complete financial statements. As a result, these unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. In the opinion of management, all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the financial position of the Company and the results of its operations have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the complete fiscal year. Subsequent events were evaluated through the date of issuance of these consolidated financial statements at the time this quarterly report on Form 10-Q was filed with the Securities and Exchange Commission (“SEC”). For a more complete understanding of the Company’s operations and financial position, reference is made to the consolidated financial statements of the Company, and related notes thereto, filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, previously filed with the SEC.
(2) Going Concern
The accompanying financial statements have been prepared assuming the Company will continue as a going concern.
The Company experienced a net loss attributable to Delta common stockholders of $148.6 million for the nine months ended September 30, 2010, and as of September 30, 2010 had a working capital deficiency of $85.8 million, including $21.5 million outstanding under Delta’s Second Amended and Restated Credit Agreement (the “Credit Agreement” or the “credit facility”) which is due on January 15, 2011 and $71.6 million outstanding under the credit agreement of DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary, which is due on August 31, 2011. In addition, the holders of the Company’s $115.0 million principal amount of 33/4% Senior Convertible Notes due 2037 have the right to require the Company to purchase all or a portion of such notes on May 1, 2012 (or thereafter on each May 1 in 2017, 2022, 2027 and 2032). The ongoing losses, near term credit maturities, and working capital deficiency raise substantial doubt about the Company’s ability to continue as a going concern.
As of and for the nine months ended September 30, 2010, the Company was in compliance with covenants under its credit facility related to its financial ratios, maximum cash on hand and accounts payable. The Company had $13.5 million of availability under its credit agreement based upon the $35.0 million borrowing base in effect at September 30, 2010, and had cash on hand of $14.2 million.
On April 1, 2010, DHS amended its existing credit facility with Lehman Commercial Paper, Inc. (“LCPI”) and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt,” bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants. The DHS facility is non-recourse to Delta.

6


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(2) Going Concern, Continued
The Company does not currently have the liquidity necessary to repay the borrowings under its credit facility due on January 15, 2011. Further, in accordance with the current terms of Delta’s credit facility, the Company is limited to capital expenditures of $18.5 million for the quarter ending December 31, 2010 (based on the original limitation of $10.0 million for the quarter ending December 31, 2010 plus $8.5 million carried forward from the quarter ended September 30, 2010).
In November 2009, the Company retained Morgan Stanley and Evercore Partners to evaluate and advise the Board of Directors on strategic alternatives to enhance shareholder value, including but not limited to the sale of some or all of the Company’s assets, entering into partnerships or joint ventures, or the sale of the entire Company.
On July 23, 2010, the Company entered into a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of $130.0 million. Also on July 23, 2010, the Company and its credit facility banks entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and conditions, including, among other amendments, that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the credit facility are described in Note 7, “Long Term Debt.” The Wapiti Transaction closed on July 30, 2010 with approximately $108.5 million used to reduce amounts outstanding under the credit facility, $3.7 million used to pay transaction related costs, and $17.8 million paid into escrow pending the receipt of third party consents required to transfer ownership of certain properties involved in the Wapiti Transaction. The funds in escrow were released in October 2010 and were used to further reduce amounts outstanding under the Company’s credit facility (see Note 14, “Subsequent Events”). The proceeds from the Wapiti Transaction allowed the Company to substantially reduce its outstanding debt and when combined with the post Wapiti Transaction borrowing base, provided the liquidity necessary to fund the Company’s third and fourth quarter 2010 development plan. Under the credit facility there are no further scheduled or special borrowing base redeterminations before the maturity of the facility in January 2011, and thus, management anticipates having adequate liquidity to fund operations. As noted below, the Company is in the process of refinancing the existing credit facility.
The Wapiti Transaction was a part of a competitive process initiated in conjunction with Delta’s previously announced strategic alternatives process. This process was concluded with the completion of the Wapiti Transaction and the Company’s focus has returned to creating value with its core assets through operations. The Board of Directors may reevaluate the renewal of the strategic alternatives process at a later time.
Taking into consideration the assets sold and proceeds received to date as a result of the strategic alternatives process, the Company will need to raise additional cash capital or complete the refinancing of its existing credit facility with new or existing lenders in order to pay its outstanding borrowings under the credit facility which are due January 15, 2011. As such, the Company expects to replace the existing facility prior to its maturity, although it is expected that the interest terms and covenant

7


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(2) Going Concern, Continued
requirements will be more expensive and restrictive, respectively, than the current facility’s rates and terms. The initial term of any new credit facility is expected to provide for maturity prior to May 1, 2012, when the holders of the Company’s $115.0 million principal amount of 33/4% Senior Convertible Notes have the right to require the Company to purchase all or a portion of the notes. As a result, it is anticipated that prior to May 1, 2012, the Company will need to obtain additional capital in order to repay any amounts outstanding under any new credit facility and to purchase any 3 3/4% Senior Convertible Notes required by the holders of such notes to be purchased by the Company.
There can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement when due, or, if not sufficient, or if additional defaults occur, that the lenders will be willing to waive the defaults or amend the agreement. In addition, there can be no assurance that cash flow from operations and other sources of liquidity, including asset sales or joint venture or other industry partnerships, will be sufficient to meet contractual, operating and capital obligations including those under any replacement credit facility. The financial statements do not include any adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its obligations.
(3) Summary of Significant Accounting Policies
   
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of the Company. All inter-company balances and transactions have been eliminated in consolidation. Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures, including CRB Partners, LLC and through the date of the Wapiti Transaction, PGR Partners, LLC. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. As Amber Resources Company of Colorado (“Amber”) is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods presented. The Company does not have any off-balance sheet financing arrangements (other than operating leases) or any unconsolidated special purpose entities.
Investments in operating entities where the Company has the ability to exert significant influence, but does not control the operating and financial policies, are accounted for using the equity method. The Company’s share of net income of these entities is recorded as income (losses) from unconsolidated affiliates in the consolidated statements of operations. Investments in operating entities where the Company does not exert significant influence are accounted for using the cost method, and income is only recognized when a distribution is received.
Certain reclassifications have been made to amounts reported in the previous periods to conform to the current presentation. Among other items, revenues and expenses on certain properties that were sold and where there is no continuing involvement, during the nine months ended September 30, 2010 have been reclassified to income (loss) from discontinued operations for all periods presented. Such reclassifications had no effect on net loss attributable to Delta common stockholders.
   
Cash Equivalents
Cash equivalents consist of money market funds and certificates of deposit. The Company considers all highly liquid investments with maturities at the date of acquisition of three months or less to be cash equivalents.

8


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
   
Inventories
Inventories consist of pipe and other production equipment not yet in use. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value. During the three months ended June 30, 2009, the Company recorded an impairment of $4.3 million to the carrying value of its inventories, which is reflected in the accompanying consolidated statements of operations for the nine months ended September 30, 2009 as a component of dry hole costs and impairments.
   
Revenue Recognition
   
Oil and Gas
Revenues are recognized when title to the products transfers to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue. Under that method, the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers. A liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of September 30, 2010 and December 31, 2009, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.
   
Drilling and Trucking
The Company earns its contract drilling revenues under daywork or turnkey contracts. The Company recognizes revenues on daywork contracts for the days completed based on the dayrate specified in the contract. Turnkey contracts are accounted for on a percentage-of-completion basis. The costs of drilling the Company’s own oil and gas properties are capitalized in oil and gas properties as the expenditures are incurred. Trucking and hauling revenues are recognized based on either an hourly rate or a fixed fee per mile depending on the type of vehicle, the services performed, and the contract terms.
   
Property and Equipment
The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological or geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss until all costs have been recovered.

9


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
Depreciation and depletion of capitalized acquisition, exploration and development costs are computed on the units-of-production method by individual fields as the related proved reserves are produced.
Drilling equipment is recorded at cost or estimated fair value upon acquisition and depreciated on a component basis using the straight-line method over its estimated useful life ranging from five to 15 years. Pipelines and gathering systems and other property and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives ranging from three to 40 years.
   
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment at least annually, or more frequently when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.
Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. For proved properties, if the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized are permanent and may not be restored in the future.
The Company assesses proved properties on an individual field basis for impairment on at least an annual basis. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. For the three and nine months ended September 30, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized. As a result of such assessment, the Company recorded an impairment provision to proved properties of $1.9 million for the three months ended September 30, 2009 and $3.1 million for the nine months ended September 30, 2009. The impairment provisions for the three and nine months ended September 30, 2009 are included within dry hole costs and impairments in the accompanying statement of operations.
For unproved properties, the need for an impairment charge is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded impairment provisions attributable to unproved properties of zero and $20.6 million for the three months ended September 30, 2010 and 2009, respectively, and $22.5 million and $103.6 million for the nine months ended September 30, 2010 and 2009, respectively. The $22.5 million impairment for the nine months ended September 30, 2010 included $11.4 million related to the Company’s Columbia River Basin leasehold, $5.0 million related to the Company’s Hingeline leasehold, $3.8 million related to the Company’s Haynesville leasehold, $1.6 million related to the Company’s Delores River leasehold and $661,000 related to the Company’s Howard Ranch leasehold. For the three months ended September 30, 2009, the Company also recorded an impairment of $10.5 million to reduce the Company’s Vega area land carrying value to its estimated fair value. Lastly, the Company recorded impairments of $4.8 million and $1.9 million to reduce the Paradox pipeline carrying value to its estimated fair value during the three months ended June 30, 2010 and 2009, respectively. These impairment provisions are included within dry hole costs and impairments in the accompanying statements of operations for the three and nine months ended September 30, 2010 and 2009.

10


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
During the remainder of 2010, the Company plans to develop and evaluate certain proved and unproved properties. Favorable or unfavorable drilling results or changes in commodity prices may cause a revision to estimates of those properties’ future cash flows. Such revisions of estimates could require the Company to record additional impairment provisions in the period of such revisions.
   
Asset Retirement Obligations
The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller from whom the Company acquired the properties. The following is a reconciliation of the Company’s asset retirement obligations from January 1, 2010 to September 30, 2010 (in thousands):
         
Asset retirement obligation — January 1, 2010
  $ 10,539  
Accretion expense
    365  
Change in estimate
    (188 )
Obligations incurred (from new wells)
    282  
Obligations assumed
     
Obligations on sold properties
    (4,034 )
Obligations settled
    (1,044 )
 
     
Asset retirement obligation — September 30, 2010
    5,920  
Less: current portion of asset retirement obligation
    (1,978 )
 
     
Long-term asset retirement obligation
  $ 3,942  
 
     
   
Comprehensive Income (Loss)
Comprehensive income (loss) includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, if any. For the three months ended September 30, 2010 comprehensive income was $10.7 million and for the three months ended September 30, 2009 comprehensive loss was $101.0 million. For the nine months ended September 30, 2010 and 2009, comprehensive loss was $157.7 million and $310.9 million, respectively.
   
Financial Instruments
The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, collar agreements, swaps or options. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices. The Company has not elected hedge accounting and recognizes mark-to-market gains and losses in earnings currently.
The Company is exposed to the fluctuations in natural gas or crude oil prices due to the nature of business in which the Company is primarily involved. In order to mitigate the risks associated with uncertain cash flows from volatile commodity prices and to provide stability and predictability in the Company’s future revenues, the Company periodically enters into commodity price risk management transactions to manage its exposure to gas and oil price volatility.
At September 30, 2010, all of the Company’s outstanding derivative contracts were fixed price swaps. Under the swap agreements, the Company receives the fixed price and pays the floating index price. The Company’s swaps

11


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
are settled in cash on a monthly basis. By entering into swaps, the Company effectively fixes the price that it will receive for a portion of its production.
The following table summarizes the Company’s open derivative contracts at September 30, 2010:
                                         
                                    Net Fair Value  
                        Remaining       Asset (Liability) at  
Commodity   Volume   Fixed Price     Term   Index Price   September 30, 2010  
                                    (In thousands)  
Crude oil
    1,000     Bbls / Day1   $ 52.25     Oct ’10 - Dec ’10   NYMEX — WTI   $ (2,600 )
Crude oil
    500     Bbls / Day   $ 57.70     Jan ’11 - Dec ’11   NYMEX — WTI     (4,404 )
Natural gas
    6,000     MMBtu / Day   $ 5.720     Oct ’10 - Dec ’10   NYMEX — HHUB     977  
Natural gas
    15,000     MMBtu / Day   $ 4.105     Oct ’10 - Dec ’10   CIG     705
Natural gas
    5,367     MMBtu / Day   $ 3.973     Oct ’10 - Dec ’10   CIG     187
Natural gas
    12,000     MMBtu / Day   $ 5.150     Jan ’11 - Dec ’11   CIG     5,006  
Natural gas
    3,253     MMBtu / Day   $ 5.040     Jan ’11 - Dec ’11   CIG     1,229  
 
                                     
 
                                  $ 1,100
 
                                     
 
1  
As a result of the closing of the Wapiti Transaction, for the period from October to December 2010, derivative contract volumes were anticipated to exceed physical production volumes in certain months. Accordingly, in October 2010, the Company partially terminated its November and December 2010 derivatives for a cost of $729,000 to reduce the hedged volume from 1,000 barrels per day to 625 barrels per day.
The pre-credit risk adjusted fair value of the Company’s net derivative assets as of September 30, 2010 was $617,000. A credit risk adjustment of $483,000 to the fair value of the derivatives increased the reported amount of the net derivative assets on the Company’s consolidated balance sheet to $1.1 million.
The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and master netting counterparty. The following table summarizes the fair values and location in the Company’s consolidated balance sheet of all derivatives held by the Company as of September 30, 2010 (in thousands):
             
Derivatives Not Designated as            
Hedging Instruments   Balance Sheet Classification     Fair Value  
Commodity Swaps
  Derivative Instruments — Current Assets, net   $ 1,165  
Commodity Swaps
  Derivative Instruments — Long-Term Liabilities, net     (65 )
 
             
Total
          $ 1,100  
 
             
The following table summarizes the realized and unrealized gains and losses and the classification in the consolidated statement of operations of derivatives not designated as hedging instruments for the nine months ended September 30, 2010 (in thousands):
             
            Amount of Gain  
Derivatives Not Designated as   Location of Gain (Loss) Recognized in     (Loss) Recognized in  
Hedging Instruments   Income on Derivatives     Income on Derivatives  
Commodity Swaps
  Realized Loss on Derivative Instruments, net — Other Income and (Expense)   $ (5,132 )
Commodity Swaps
  Unrealized Gain on Derivative Instruments, net — Other Income and (Expense)     28,072  
 
             
 
          $ 22,940  
 
             

12


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3)  Summary of Significant Accounting Policies, Continued
Executive Severance Agreements
On May 26, 2009, the Company’s then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from the Company. In conjunction with Mr. Parker’s resignation, Delta entered into a Severance Agreement, effective as of the close of business on May 26, 2009, whereby Mr. Parker resigned from his positions as Chairman of the Board, Chief Executive Officer and as a director of Delta, as well as his positions as a director, officer and employee of Delta’s subsidiaries. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4,700,000 in cash, issue to him 1,000,000 shares of Delta common stock, pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms.
The table below summarizes the total executive severance expense included in the accompanying statements of operations for the nine months ended September 30, 2009 (in thousands):
         
Cash consideration — immediately available funds
  $ 1,812  
Cash consideration — rabbi trust
    2,888  
Stock consideration — rabbi trust
    1,700  
 
     
Subtotal
    6,400  
Performance shares forfeited
    (2,293 )
Retention stock forfeited
    (525 )
Health, medical and other benefits payable
    75  
Legal costs and other expenses
    82  
 
     
Total executive severance expense
  $ 3,739  
 
     
In accordance with the terms of the Severance Agreement, Mr. Parker received a portion of the cash consideration in immediately available funds, and the remaining cash consideration and the shares were deposited in a rabbi trust and distributed to Mr. Parker on November 27, 2009. The assets of the rabbi trust were required to be consolidated into the financial statements until disbursed.
Equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period being completed and retention stock forfeited prior to vesting as a result of the Severance Agreement were reversed and reflected as a reduction of executive severance expense.
All transactions associated with the Parker Severance Agreement were recorded in fiscal year 2009.

13


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
On July 6, 2010, John Wallace, the then President, Chief Operating Officer and a Director of the Company, resigned from all of his positions as director, officer and employee of the Company and any of its subsidiaries. In conjunction with such resignation, the Company entered into a severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and certain other interests he might claim arising from his efforts in his previous capacities with the Company and its subsidiaries, and (b) make himself reasonably available to answer questions to facilitate an orderly transition. Under the terms of his severance arrangement, the Company paid Mr. Wallace a lump sum of $1,600,000, paid him his salary for the full month in which his resignation occurred and for his accrued vacation days, reimbursed him for his reasonable business expenses incurred through the effective date of the agreement, and agreed to provide to him insurance benefits similar to his pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage under applicable law. The severance agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms.
The table below summarizes the total executive severance expense included in the accompanying statements of operations for the nine months ended September 30, 2010 (in thousands):
         
Cash consideration — immediately available funds
  $ 1,600  
Performance shares forfeited
    (2,274 )
 
     
Total executive severance expense (benefit)
  $ (674 )
 
     
Equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period being completed as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.
   
Stock Based Compensation
The Company recognizes the cost of share based payments over the period the employee provides service and includes such costs in general and administrative expense in the statements of operations.
   
Income (Loss) from Unconsolidated Affiliates
Income (loss) from unconsolidated affiliates includes the Company’s share of earnings or losses from equity method investments. During the nine months ended September 30, 2010, Delta Oilfield Tank Company (“DOTC”) reported continuing losses from operations which, if recorded, would have created a deficit in the investment in DOTC. In accordance with accounting standards, the Company did not recognize its share of the losses for the nine months ended September 30, 2010 as the Company is not obligated to make future capital contributions to DOTC. During the quarter ended June 30, 2009, the Company recorded a $2.1 million impairment provision to its investment in DOTC and a $917,000 impairment provision to its investment in the entity that was expected to operate the Paradox pipeline. These impairment provisions are included within income (loss) from unconsolidated affiliates for the nine months ended September 30, 2009.
During the nine months ended September 30, 2010, the Company sold its 50% interest in Ally Equipment, LLC for $1.5 million, including $250,000 received during the third quarter and five $250,000 quarterly installments to be paid each quarter end commencing on December 31, 2010. The Company recognized a loss of $522,000 on the transaction which is included as a component of income (loss) from unconsolidated affiliates for the three months and nine months ended September 30, 2010.

14


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
At December 31, 2009, the Company owned a 5% interest in Collbran Valley Gas Gathering, LLC (“CVGG”) which operates a pipeline in the Piceance Basin through which the Company transports its produced gas to the sales point. During the fourth quarter of 2009, the Company recorded an impairment of its investment in CVGG to reduce the carrying value to its fair value of $3.5 million. In January 2010, the Company divested its 5% interest in CVGG for cash proceeds of $3.5 million (and a subsequent adjustment of an additional $129,000), plus an additional $2.0 million of proceeds contingent on volume deliveries through the CVGG system of Delta gas between January 1, 2010 and June 30, 2011. Based on current production levels, the Company is not likely to earn the contingent consideration without the initiation of a continuous drilling program which could only be undertaken with additional funding beyond the Company’s existing capital resources.
   
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated based on a “more likely than not” standard, and to the extent this threshold is not met, a valuation allowance is recorded. The Company is currently providing a full valuation allowance on its net deferred tax assets, including the net deferred tax assets of DHS.
   
Income (Loss) per Common Share
Basic income (loss) per share is computed by dividing net income (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted income (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, convertible debt, stock options, restricted stock and warrants. (See Note 11, “Earnings Per Share”).
   
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves, bad debts, depletion and impairment of oil and gas properties, income taxes, derivatives, asset retirement obligations, contingencies and litigation accruals. Actual results could differ from these estimates.

15


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(3) Summary of Significant Accounting Policies, Continued
   
Recently Issued and Adopted Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which provides amendments to FASB ASC Topic 820, Fair Value Measurements and Disclosures. The objective of ASU 2010-06 is to provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. The Company adopted ASU 2010-06 effective January 1, 2010, which did not have an impact on its consolidated financial statements, other than additional disclosures.
(4) Oil and Gas Properties
   
Unproved Undeveloped Offshore California Properties
The Company previously owned direct and indirect ownership interests ranging from 2.49% to 100% in five unproved undeveloped offshore California oil and gas properties. Delta and its 92% owned subsidiary, Amber, were among twelve plaintiffs in a lawsuit that was filed in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. government materially breached the terms of forty undeveloped federal leases, some of which are part of its offshore California properties. During 2009, the Company received net proceeds of $95.8 million after overrides and conveyed its leases back to the United States. Accordingly, the Company no longer has any remaining unproved undeveloped offshore California property interests.
2010 — Divestitures
During the nine months ended September 30, 2010, the Company divested of its interests in certain non-core properties for gross proceeds of $965,000 and the assumption of plugging and abandonment obligations. Proved reserves attributable to these properties were insignificant.
The Company considered the total purchase price in the Wapiti Transaction and allocated the purchase price to the properties using internal discounted cash flow calculations based upon the Company’s estimates of reserves and determined that impairment provisions of $93.2 million related to proved properties and $3.0 million related to unproved properties were required to be recognized during the three months ended June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment provision is included within dry hole costs and impairments in the accompanying statements of operations and the remaining $92.2 million is included within loss on sale of discontinued operations.
   
Discontinued Operations
In accordance with accounting standards, the results of operations and impairment loss relating to certain of the Wapiti Transaction properties have been reflected as discontinued operations. Properties associated with the Wapiti Transaction in which the Company only sold half of its interest continue to be reported as a component of continuing operations. The fields classified as discontinued operations are fields in which the Company sold all of its interest including the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as the Company’s interest in its wholly-owned subsidiary Piper Petroleum. In a separate transaction, during the three months ended September 30, 2010, the Company sold its interest in the Howard Ranch field and has included this property as discontinued operations as well.

16


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(4) Oil and Gas Properties, Continued
The following table shows the total oil and gas segment revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the three and nine months ended September 30, 2010 and 2009 (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
Revenues
  $ 1,344     $ 2,475     $ 9,623     $ 8,255  
 
                               
Operating expenses:
                               
 
                               
Lease operating expense
    429       757       2,676       3,740  
Transportation expense
    181       60       1,459       1,196  
Production taxes
    116       438       611       544  
Depreciation, depletion, amortization and accretion
    33       5,649       13,837       19,477  
Impairment provision
                92,162        
 
                       
Total operating expenses
    759       6,904       110,745       24,957  
 
                       
 
                               
Income (loss) from discontinued operations
    585       (4,429 )     (101,122 )     (16,702 )
Income tax expense
                       
 
                       
 
                               
Income (loss) from results of operations of discontinued properties, net of tax
    585       (4,429 )     (101,122 )     (16,702 )
 
                               
Gain on sale of discontinued operations
    28,910             28,910        
 
                       
 
                               
Total gain (loss) from discontinued operations
  $ 29,495     $ (4,429 )   $ (72,212 )   $ (16,702 )
 
                       
On July 30, 2010, the Company closed on the Wapiti Transaction for cash proceeds of $130.0 million, with approximately $108.5 million used to reduce amounts outstanding under the credit facility, $3.7 million used to pay transaction related costs, and $17.8 million initially paid into escrow pending the receipt of third party consents required to transfer ownership of certain properties involved in the Wapiti Transaction. The escrowed proceeds were received in October 2010. The Company recognized a gain on sale for the closing of the Wapiti Transaction in the three months ended September 30, 2010 of $29.6 million. The recognized gain is subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement.
On August 27, 2010, the Company closed on the Howard Ranch sale for cash proceeds of $550,000. The Company recognized a loss on sale of $687,000, which is subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement.
(5) DHS Drilling
On September 30, 2010, the Company owned a 49.8% ownership interest in DHS. The remaining interest is owned by Chesapeake Energy Corporation, 47.2%, and 3% by DHS executive officers and management. Delta has the right to use all of the DHS rigs on a priority basis.

17


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(5) DHS Drilling, Continued
The carrying value of DHS’s drilling rigs and related equipment is assessed for impairment whenever circumstances indicate an impairment may exist. During the quarter ended June 30, 2009, the fleet rig utilization rate declined approximately 68% from the first quarter of 2009 and the average period end contract day rate declined by approximately 29% from the first quarter of 2009. In addition, DHS’s efforts to market spare equipment and observations at industry auctions indicated that with industry-wide active rig counts in decline, spare equipment values had declined. As a result of these indicators of possible impairment, an analysis was performed and an impairment provision of $6.5 million was recorded to reduce the carrying value of three drilling rigs and other spare rig equipment to their respective fair values. No such impairment provisions were recorded during the three and nine months ended September 30, 2010 as rig utilization has continued to improve throughout 2010.
In January 2010, DHS entered into a daywork drilling contract with Desarrollos y Perforaciones De Mexico (“DPM”) to drill geothermal wells for the benefit of the Mexican national electric company (“CFE”) in the state of Puebla. The rig was released in July after drilling two wells. A total of $3,713,000 has been invoiced to DPM for the project with $1,588,000 being collected to date. The balance of $2,125,000 has been reserved as a doubtful account due to concerns regarding collection. Legal action is being taken to collect the amount owed to DHS and the rig is in the Casper, Wyoming yard for minor reconditioning. In addition, another DHS customer has filed bankruptcy during the quarter and its balance of $104,000 has been reserved as a doubtful account as well.
(6) Fair Value Measurements
The Company follows accounting guidance which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. As required, the Company applied the following fair value hierarchy:
   
Level 1 — Assets or liabilities for which the item is valued based on quoted prices (unadjusted) for identical assets or liabilities in active markets.
 
   
Level 2 — Assets or liabilities valued based on observable market data for similar instruments.
 
   
Level 3 — Assets or liabilities for which significant valuation assumptions are not readily observable in the market; instruments valued based on the best available data, some of which is internally-developed, and considers risk premiums that a market participant would require.
The level in the fair value hierarchy within which the fair value measurement in its entirety falls shall be determined based on the lowest level input that is significant to the fair value measurement in its entirety.
Derivative liabilities consist of future oil and gas commodity swap contracts valued using both quoted prices for identically traded contracts and observable market data for similar contracts (NYMEX WTI oil, NYMEX Henry Hub gas and CIG gas swaps — Level 2).
Proved property impairments — The fair values of the proved properties are estimated using internal discounted cash flow calculations based upon the Company’s estimates of reserves and are considered to be level three fair value measurements.
Asset retirement obligations — The initial fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon the Company’s asset retirement obligations, including revisions of the estimated fair values during the nine months ended September 30, 2010 and 2009.

18


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(6) Fair Value Measurements, Continued
The following table lists the Company’s fair value measurements by hierarchy as of September 30, 2010 (in thousands):
                         
    Fair Value Measurements
    Quoted Prices   Significant   Significant
    in Active Markets   Other Observable   Unobservable
    for Identical Assets   Inputs   Inputs
Assets (Liabilities)   (Level 1)   (Level 2)   (Level 3)
Recurring
                       
Derivative assets
  $     $ 1,100     $  
(7) Long Term Debt
   
Installments Payable on Property Acquisition
On February 28, 2008, the Company closed a transaction with EnCana to jointly develop a portion of EnCana’s leasehold in the Vega Area of the Piceance Basin. The remaining installments payable are recorded in the accompanying consolidated financial statements as current and long-term liabilities at a discounted value. The discount is being accreted on the effective interest method over the term of the installments, including accretion of $1.3 million and $1.9 million for the three months ended September 30, 2010 and 2009, respectively, and accretion of $3.8 million and $5.6 million for the nine months ended September 30, 2010 and 2009, respectively. On October 28, 2010, the Company paid the second of three installments payable related to the transaction (see Note 14, “Subsequent Events”).
   
7% Senior Unsecured Notes, due 2015
On March 15, 2005, the Company issued 7% senior unsecured notes for an aggregate principal amount of $150.0 million. The Company was in compliance with the covenants under the indenture as of September 30, 2010 (See Note 12, “Guarantor Financial Information”). The fair value of the Company’s senior unsecured notes at September 30, 2010 was approximately $109.5 million.
   
33/4% Senior Convertible Notes, due 2037
On April 25, 2007, the Company issued $115.0 million aggregate principal amount of 33/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The Notes were recorded based on the estimated fair value of the liability component and the equity component. The debt discount on the liability component is accreted over the expected life of the Notes, including $1.2 million and $1.1 million of accretion for the three months ended September 30, 2010 and 2009, respectively, and $3.4 million and $3.3 million of accretion for the nine months ended September 30, 2010 and 2009, respectively. Combined with the amortization of debt discount, the Notes had an effective interest rate of approximately 7.8% and 7.6% with total interest costs of $2.2 million for each of the three months ended September 30, 2010 and 2009, respectively, and interest costs of $6.6 million and $6.5 million for the nine months ended September 30, 2010 and 2009, respectively. The fair value of the Notes at September 30, 2010 was approximately $88.3 million.

19


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(7) Long Term Debt, Continued
   
Credit Facility — Delta
On July 23, 2010, Delta entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement, with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to its credit agreement in which, among other changes, the requisite lenders consented to the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds from the transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011. In addition, the Fourth Amendment imposed capital expenditures limitations of $18.0 million for the quarter ending September 30, 2010, $10.0 million for the quarter ending December 31, 2010, and $2.0 million for the period from January 1, 2011 to January 15, 2011, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier specified period to a subsequent specified period. The Fourth Amendment added a maximum cash on hand covenant which limits the Company’s cash and cash equivalents to $10.0 million at any time, with any excess above such limit required to be used to pay down borrowings under the credit facility within three business days. Finally, the Fourth Amendment requires cash disbursements for general and administrative expenses to be within a 10% variance of projected general and administrative expenses provided to the lending banks in conjunction with the execution of the Fourth Amendment.
The Company was in compliance with its financial ratio covenants, capital expenditures, cash on hand and accounts payable limitations under the Credit Agreement as of September 30, 2010. Based on the Company’s current operating projections, the Company believes it will remain in compliance with the debt covenants through its maturity in January 2011. However, there can be no assurance that the actions undertaken by the Company will be sufficient to repay the obligations under the credit agreement when due, or, if not sufficient, or if additional defaults occur, that the lenders will be willing to waive the defaults or amend the agreement.
Borrowings under the credit facility were $21.5 million at September 30, 2010, with remaining availability of $13.5 million.
Because the credit facility matures in January 2011, the debt is classified as a current liability in the September 30, 2010 consolidated balance sheet.

20


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(7) Long Term Debt, Continued
   
Credit Facility — DHS
On April 1, 2010, DHS amended its existing credit facility with LCPI and renegotiated certain terms of the agreement including obtaining waivers for all covenant violations through March 31, 2010. The terms of the amended agreement required principal payments of $7,677,713 paid on April 1, 2010 and $2,000,000 paid on each of May 1, 2010, August 1, 2010 and November 1, 2010, with a remaining $2,000,000 principal payment due on January 1, 2011, and a $5,000,000 principal payment due on each of April 1, 2011 and July 1, 2011 with the remaining balance of $57,589,787 due at maturity (August 31, 2011). In addition to the required payments, DHS may be required to prepay any remaining outstanding principal with the “Net Cash Proceeds from any Asset Sale,” as defined by the credit facility, and any such prepayment shall be applied to, first, prepay the immediately succeeding Scheduled Installment in full, second, prepay all interest payable on the immediately succeeding Interest Payment Date in full, third, pay the second succeeding Scheduled Installment in full and fourth, prepay the remaining principal balance of the remaining loans. DHS is also required to prepay the principal amount of the loans in an amount equal to 75% of the “Excess Cash Flow,” as defined by the credit facility, for such fiscal quarter. The only financial covenant remaining in the DHS credit agreement is a minimum EBITDA covenant of $1,000,000 for the three months ending September 30, 2010 and $1,500,000 for each subsequent quarter. In addition, the amendment imposed capital expenditures limitations of $1,200,000 for any fiscal quarter. Notwithstanding the $1,200,000 per quarter limitation on capital expenditures, the amendment imposes aggregate capital expenditure limitations of $3,500,000 for fiscal year 2010 and $2,330,137 for fiscal year 2011. The interest rate has been adjusted to LIBOR plus 625 basis points, subject to a LIBOR floor rate of 2.75%. DHS was in compliance with its amended minimum EBITDA covenant and capital expenditures limitation for the three months ended September 30, 2010.
Because the credit facility matures in August 2011, the debt is classified as a current liability in the September 30, 2010 consolidated balance sheet.
(8) Commitments and Contingencies
The $115.0 million in principal amount of 33/4% Senior Convertible Notes due 2037 will mature on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require the Company to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032 at a price which is required to be paid in cash, equal to 100% of the principal amount of the Notes to be repurchased.
The Company is currently engaged in arbitration with 212 Resources Corporation (“212”) with regard to a dispute involving a May 18, 2008 Oil and Gas Fluid Processing Agreement (the “Agreement”) between 212 and the Company. The Agreement requires 212 to design, construct, and operate “Mobile Pods” to treat and discharge to surface waters fluid produced by the Company’s oil and gas operations in compliance with applicable law and permits, and requires the Company to pay 212 approximately $500,000 per month commencing on the earlier of the date that such Mobile Pod is (a) first Available, or (b) first used to provide the contemplated services. The term “Available,” as used in the Agreement, means the first date that a Mobile Pod is mechanically capable of providing the contemplated services (or would have been mechanically capable of providing such services but for the Company’s failure to perform any of its obligations under the Agreement). On October 27, 2009, 212 filed a Demand for Arbitration and Statement of Claim and alleged that the Company delayed the performance of its duty to obtain permits and construct the site under the Agreement. 212 contends, in essence, that the Company delayed obtaining permits for the operation of the Mobile Pods and that the Company owes the monthly fee for the Mobile Pods for the period commencing on October 1, 2009. The Company has denied 212’s claims and

21


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(8) Commitments and Contingencies, Continued
contends, in essence, that 212 has still not demonstrated that the Mobile Pods are capable of treating and discharging to surface waters fluid produced by the Company’s oil and gas operations in compliance with applicable law and permits. The Company has also filed counterclaims. The matter is currently set for arbitration on November 29, 2010, but the Company has filed a motion seeking a delay of the hearing for a time sufficient to obtain and analyze a variety of test results to determine whether or not the operation of the Mobile Pods complies with applicable law and permits. While the Company believes it has meritorious defenses to 212’s claims and has valid counterclaims, the Company is unable to predict the ultimate outcome of the arbitration.
The Company’s indirect, 49.8% owned affiliate DHS Drilling Company (“DHS”) and certain of its officers and employees, among others, have been notified by the Office of the Inspector General of the Export-Import Bank of the United States and the U.S. Department of Justice that they are the subject of an investigation in connection with a loan guaranty sought from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican bank to a DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the investigation, which is currently in its initial stages. This investigation is subject to uncertainties and, as such, DHS is unable to estimate the nature of any possible loss or range of loss that may result. DHS and the Company may also be responsible to indemnify certain officers and employees in connection with their individual defenses relating to the investigation.
(9) Stockholders’ Equity
   
Preferred Stock
The Company has 3,000,000 shares of preferred stock authorized, issuable from time to time in one or more series. As of September 30, 2010 and December 31, 2009, no shares of preferred stock were outstanding.
   
Common Stock
During the three months ended March 31, 2010, the Company issued 480,778 fully vested shares to the non-employee members of the Board of Directors in consideration for their service on the Board for the year ended December 31, 2009. On September 16, 2010, the Company granted 5.1 million shares of non-vested common stock to certain employees. The shares vest in full on July 1, 2011.

22


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(9) Stockholders’ Equity, Continued
   
Treasury Stock
During 2008, DHS implemented a retention bonus plan whereby certain key managers of DHS were granted shares of Delta common stock, one-third of which vest on each one year anniversary of the grant date. In addition, similar incentive grants were made to DHS executives during 2008. The shares of Delta common stock used to fund the grants were proportionally provided by Delta’s issuance of new shares to DHS employees and Chesapeake’s contribution to DHS of Delta shares purchased in the open market. The Delta shares contributed by Chesapeake are recorded at historical cost in the accompanying consolidated balance sheet as treasury stock and will be carried as such until the shares vest. The Delta shares contributed by Delta are treated as non-vested stock issued to employees and therefore recorded as additions to additional paid in capital over the vesting period. Compensation expense is recorded on all such grants over the vesting period.
   
Stock Based Compensation
The Company recognized stock compensation included in general and administrative expense as follows (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
Non-vested stock
  $ 1,716     $ 2,436     $ 8,187     $ 5,371  
Stock options
    109             109        
Performance shares
    131       358       512       2,062  
 
                       
Total
  $ 1,956     $ 2,794     $ 8,808     $ 7,433  
 
                       
The Company recognizes the cost of share based payments over the period during which the employee provides service. During the three months ended September 30, 2010, the Company issued 250,000 fully vested stock options at an exercise price of $0.79 per share to the Company’s Chief Executive Officer. Other than the stock option issuance during the third quarter of 2010, the Company had not issued stock options since July 2005 and as all prior outstanding stock options are fully vested, no compensation cost was recognized with respect to stock options in the 2009 periods shown in the table above. Exercise prices for options outstanding under the Company’s various plans as of September 30, 2010 ranged from $0.79 to $15.34 per share. At September 30, 2010, there was no unrecognized compensation cost related to stock options as all outstanding options are vested. At September 30, 2010, the Company had 1,608,000 options outstanding at a weighted average exercise price of $7.25 per share. At September 30, 2010, the Company had 7,775,000 non-vested shares outstanding and 80,000 performance shares outstanding. At September 30, 2010, the total unrecognized compensation cost related to the performance shares and the non-vested portion of restricted stock was $9.3 million which is expected to be recognized over a weighted average period of 1.1 years.

23


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(10) Income Taxes
Income tax expense (benefit) attributable to loss from continuing operations was approximately $86,000 and $265,000 for the three months ended September 30, 2010 and 2009, respectively, and $564,000 and $(53,000) for the nine months ended September 30, 2010 and 2009, respectively.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment. Based upon the level of historical taxable income, significant book losses during the current and prior periods, and projections for future results of operations over the periods in which the deferred tax assets are deductible, among other factors, management continues to conclude that the Company does not meet the “more likely than not” requirement in order to recognize deferred tax assets and a valuation allowance has been recorded for the Company’s net deferred tax assets at September 30, 2010.
During the three and nine months ended September 30, 2010, DHS recorded net operating losses and as of September 30, 2010 DHS’s deferred tax assets exceeded its deferred tax liabilities. Accordingly, based on significant recent operating losses and projections for future results, a valuation allowance was recorded for DHS’s net deferred tax assets.
During the remainder of 2010 and thereafter, the Company will continue to assess the realizability of its deferred tax assets based on consideration of actual and projected operating results and tax planning strategies. Should actual operating results improve, the amount of the deferred tax asset considered more likely than not to be realizable could be increased. Such a change in the assessment of realizability could result in a decrease to the valuation allowance and corresponding income tax benefit, both of which could be significant.
During the three and nine months ended September 30, 2010 and 2009, no adjustments were recognized for uncertain tax benefits.
(11) Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share (in thousands, except per share amounts):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
Net income (loss) attributable to Delta common stockholders
  $ 13,942     $ (96,827 )   $ (148,606 )   $ (294,698 )
 
                       
Basic weighted-average common shares outstanding
    275,306       275,465       275,437       189,740  
Add: dilutive effects of stock options and unvested stock grants
    6,757                    
 
                       
Diluted weighted-average common shares outstanding
    282,063       275,465       275,437       189,740  
 
                       
 
                               
Net income (loss) per common share attributable to Delta common stockholders
                               
Basic
  $ 0.05     $ (0.35 )   $ (0.54 )   $ (1.55 )
 
                       
Diluted
  $ 0.05     $ (0.35 )   $ (0.54 )   $ (1.55 )
 
                       

24


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(11)  Earnings Per Share, Continued
Potentially dilutive securities excluded from the calculation of diluted shares outstanding include the following (in thousands):
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2010     2009     2010     2009  
Stock issuable upon conversion of convertible notes
    3,790       3,790       3,790       3,790  
Stock options
    1,608       1,428       1,608       1,428  
Performance share grants
          150       80       150  
Non-vested restricted stock
          1,270       7,775       1,270  
 
                       
Total potentially dilutive securities
    5,398       6,638       13,253       6,638  
 
                       
(12) Guarantor Financial Information
On March 15, 2005, Delta issued $150.0 million of 7% senior notes (“Senior Notes”) that mature in 2015. In addition, on April 25, 2007, the Company issued $115.0 million of 33/4% Convertible Senior Notes due in 2037 (“Convertible Notes”). Both the Senior Notes and the Convertible Notes are guaranteed by all of the Company’s wholly-owned subsidiaries (“Guarantors”). Each of the Guarantors, fully, jointly and severally, irrevocably and unconditionally guarantees the performance and payment when due of all the obligations under the Senior Notes and the Convertible Notes. DHS, CRBP, and Amber (“Non-guarantors”) are not guarantors of the indebtedness under the Senior Notes or the Convertible Notes.
The following financial information sets forth the Company’s condensed consolidated balance sheets as of September 30, 2010 and December 31, 2009, the condensed consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009, and the condensed consolidated statements of cash flows for the nine months ended September 30, 2010 and 2009 (in thousands). For purposes of the condensed financial information presented below, the equity in the earnings or losses of subsidiaries is not recorded in the financial statements of the issuer.

25


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
September 30, 2010
                                         
            Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Entities     Entities     Eliminations     Consolidated  
Current assets
  $ 140,921     $ 298     $ 15,782     $     $ 157,001  
 
                                       
Property and equipment:
                                       
Oil and gas properties
    1,083,550             19,215       (117 )     1,102,648  
Drilling rigs and trucking equipment
    594             173,851             174,445  
Other
    78,871       32,617       1,781             113,269  
 
                             
Total property and equipment
    1,163,015       32,617       194,847       (117 )     1,390,362  
 
                                       
Accumulated depletion and depreciation
    (371,084 )     (28,702 )     (112,891 )           (512,677 )
 
                             
 
                                       
Net property and equipment
    791,931       3,915       81,956       (117 )     877,685  
 
                                       
Investment in subsidiaries
    3,570                   (3,570 )      
Other long-term assets
    109,136       2,407       126             111,669  
 
                             
 
                                       
Total assets
  $ 1,045,558     $ 6,620     $ 97,864     $ (3,687 )   $ 1,146,355  
 
                             
 
                                       
Current liabilities
  $ 162,543     $ (27 )   $ 80,279     $     $ 242,795  
 
                                       
Long-term liabilities:
                                       
Long-term debt, derivative instruments and deferred taxes
    352,605       1,801                   354,406  
Asset retirement obligations
    3,942                         3,942  
 
                             
 
                                       
Total long-term liabilities
    356,547       1,801                   358,348  
 
                                       
Total Delta stockholders’ equity
    526,822       4,846       17,585       (3,687 )     545,566  
 
                                       
Non-controlling interest
    (354 )                       (354 )
 
                             
 
                                       
Total equity
    526,468       4,846       17,585       (3,687 )     545,212  
 
                             
 
                                       
Total liabilities and equity
  $ 1,045,558     $ 6,620     $ 97,864     $ (3,687 )   $ 1,146,355  
 
                             

26


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(12) Guarantor Financial Information, Continued
Condensed Consolidated Balance Sheet
December 31, 2009
                                         
            Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Current assets
  $ 160,408     $ 448     $ 31,596     $     $ 192,452  
 
                                       
Property and equipment:
                                       
Oil and gas properties
    1,529,920       592       130,837       (585 )     1,660,764  
Drilling rigs and trucking equipment
    594             177,168             177,762  
Other
    73,383       32,916       1,919             108,218  
 
                             
Total property and equipment
    1,603,897       33,508       309,924       (585 )     1,946,744  
 
                                       
Accumulated depletion and depreciation
    (652,432 )     (24,040 )     (124,029 )           (800,501 )
 
                             
Net property and equipment
    951,465       9,468       185,895       (585 )     1,146,243  
 
                                       
Investment in subsidiaries
    80,058                   (80,058 )      
Other long-term assets
    114,820       3,787       183             118,790  
 
                             
 
                                       
Total assets
  $ 1,306,751     $ 13,703     $ 217,674     $ (80,643 )   $ 1,457,485  
 
                             
 
                                       
Current liabilities
  $ 179,302     $ 319     $ 92,579     $     $ 272,200  
 
                                       
Long-term liabilities:
                                       
Long-term debt, derivative instruments and deferred taxes
    478,710       1,801                   480,511  
Asset retirement obligations
    7,358       11       285             7,654  
 
                             
 
                                       
Total long-term liabilities
    486,068       1,812       285             488,165  
 
                                       
Total Delta stockholders’ equity
    632,843       11,572       124,810       (80,643 )     688,582  
 
                                       
Non-controlling interest
    8,538                         8,538  
 
                             
 
                                       
Total equity
    641,381       11,572       124,810       (80,643 )     697,120  
 
                             
 
                                       
Total liabilities and equity
  $ 1,306,751     $ 13,703     $ 217,674     $ (80,643 )   $ 1,457,485  
 
                             

27


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(12)  Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2010
                                         
            Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Entities     Entities     Eliminations     Consolidated  
Total revenue
  $ 20,232     $     $ 15,204     $     $ 35,436  
 
                                       
Operating expenses:
                                       
Oil and gas expenses
    10,353                         10,353  
Exploration expense
    368                         368  
Dry hole costs and impairments
    (291 )     29                   (262 )
Depreciation and depletion
    14,410             4,801             19,211  
Drilling and trucking operating expenses
                12,041             12,041  
General and administrative
    7,834       12       2,499             10,345  
Executive severance expense, net
    (674 )                       (674 )
 
                             
 
                                       
Total operating expenses
    32,000       41       19,341             51,382  
 
                             
 
                                       
Operating loss
    (11,768 )     (41 )     (4,137 )           (15,946 )
 
                                       
Other income and (expense)
    (449 )     6       (2,287 )           (2,730 )
Income tax expense
    (86 )                       (86 )
Discontinued operations
    61,715       (304 )     (31,916 )           29,495  
 
                             
 
                                       
Net income (loss)
    49,412       (339 )     (38,340 )           10,733  
 
                                       
Less income (loss) attributable to non-controlling interest
    3,209                         3,209  
 
                             
 
                                       
Net income (loss) attributable to Delta common stockholders
  $ 52,621     $ (339 )   $ (38,340 )   $     $ 13,942  
 
                             
Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2009
                                         
            Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Entities     Entities     Eliminations     Consolidated  
Total revenue
  $ 18,909     $     $ 2,589     $ (51 )   $ 21,447  
 
                                       
Operating expenses:
                                       
Oil and gas expenses
    9,554                         9,554  
Exploration expense
    891                         891  
Dry hole costs and impairments
    53,407                         53,407  
Depreciation and depletion
    20,014       51       5,545             25,610  
Drilling and trucking operations
                2,891       (73 )     2,818  
General and administrative
    8,945       32       976             9,953  
 
                             
 
                                       
Total operating expenses
    92,811       83       9,412       (73 )     102,233  
 
                             
 
                                       
Operating income (loss)
    (73,902 )     (83 )     (6,823 )     22       (80,786 )
 
                                       
Other income and (expenses)
    (14,004 )     5       (1,494 )           (15,493 )
Income tax benefit (expense)
    (265 )                       (265 )
Discontinued operations
    (1,905 )     64       (2,588 )           (4,429 )
 
                             
 
                                       
Net loss
    (90,076 )     (14 )     (10,905 )     22       (100,973 )
 
                                       
Less loss attributable to non-controlling interest
    4,146                         4,146  
 
                             
 
                                       
Net income (loss) attributable to Delta common stockholders
  $ (85,930 )   $ (14 )   $ (10,905 )   $ 22     $ (96,827 )
 
                             

28


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2010
                                         
          Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Entities     Entities     Eliminations     Consolidated  
Total revenue
  $ 74,118     $ 77     $ 36,995     $ (795 )   $ 110,395  
 
                                       
Operating expenses:
                                       
Oil and gas expenses
    35,858                         35,858  
Exploration expense
    952                         952  
Dry hole costs and impairments
    25,439       4,834       586             30,859  
Depreciation and depletion
    45,538       2       15,663       (64 )     61,139  
Drilling and trucking operating expenses
                28,666       (613 )     28,053  
General and administrative
    28,635       41       4,696             33,372  
Executive severance expense, net
    (674 )                       (674 )
 
                             
 
                                       
Total operating expenses
    135,748       4,877       49,611       (677 )     189,559  
 
                             
 
                                       
Operating loss
    (61,630 )     (4,800 )     (12,616 )     (118 )     (79,164 )
 
                                       
Other income and (expense)
    465             (6,265 )           (5,800 )
Income tax expense
    (564 )                       (564 )
Discontinued operations
    20,845       (200 )     (92,857 )           (72,212 )
 
                             
 
                                       
Net loss
    (40,884 )     (5,000 )     (111,738 )     (118 )     (157,740 )
 
                                       
Less loss attributable to non-controlling interest
    9,134                         9,134  
 
                             
 
                                       
Net loss attributable to Delta common stockholders
  $ (31,750 )   $ (5,000 )   $ (111,738 )   $ (118 )   $ (148,606 )
 
                             
Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2009
                                         
          Guarantor     Non-Guarantor     Adjustments/        
    Issuer     Entities     Entities     Eliminations     Consolidated  
Total revenue
  $ 87,840     $     $ 12,409     $ (2,984 )   $ 97,265  
 
                                       
Operating expenses:
                                       
Oil and gas expenses
    31,143                         31,143  
Exploration expense
    2,422                         2,422  
Dry hole costs and impairments
    153,067       1,896       6,508             161,471  
Depreciation and depletion
    62,830       162       18,091       (579 )     80,504  
Drilling and trucking operations
                12,238       (1,822 )     10,416  
General and administrative
    28,191       67       3,287             31,545  
Executive severance expense, net
    3,739                         3,739  
 
                             
 
                                       
Total operating expenses
    281,392       2,125       40,124       (2,401 )     321,240  
 
                             
 
                                       
Operating income (loss)
    (193,552 )     (2,125 )     (27,715 )     (583 )     (223,975 )
 
                                       
Other income and (expenses)
    (64,831 )     25       (5,459 )           (70,265 )
Income tax benefit (expense)
    (741 )           794             53  
Discontinued operations
    (8,476 )     178       (8,404 )           (16,702 )
 
                             
 
                                       
Net loss
    (267,600 )     (1,922 )     (40,784 )     (583 )     (310,889 )
 
                                       
Less loss attributable to non-controlling interest
    16,191                         16,191  
 
                             
 
                                       
Net loss attributable to Delta common stockholders
  $ (251,409 )   $ (1,922 )   $ (40,784 )   $ (583 )   $ (294,698 )
 
                             

29


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(12) Guarantor Financial Information, Continued
Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2010
                                 
            Guarantor     Non-Guarantor        
    Issuer     Entities     Entities     Consolidated  
Cash provided by (used in):
                               
Operating activities
  $ (40,857 )   $ (665 )   $ 15,564     $ (25,958 )
Investing activities
    97,888       622       (3,670 )     94,840  
Financing activities
    (104,450 )           (12,153 )     (116,603 )
 
                       
 
                               
Net increase (decrease) in cash and cash equivalents
    (47,419 )     (43 )     (259 )     (47,721 )
 
                               
Cash at beginning of the period
    58,533       74       3,311       61,918  
 
                       
 
Cash at the end of the period
  $ 11,114     $ 31     $ 3,052     $ 14,197  
 
                       
Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2009
                                 
            Guarantor     Non-Guarantor        
    Issuer     Entities     Entities     Consolidated  
Cash provided by (used in):
                               
Operating activities
  $ 15,662     $ 154     $ 4,343     $ 20,159  
Investing activities
    (140,056 )     (227 )     3,083       (137,200 )
Financing activities
    72,749             (10,500 )     62,249  
 
                       
 
                               
Net decrease in cash and cash equivalents
    (51,645 )     (73 )     (3,074 )     (54,792 )
 
                               
Cash at beginning of the period
    60,993       151       4,331       65,475  
 
                       
 
                               
Cash at the end of the period
  $ 9,348     $ 78     $ 1,257     $ 10,683  
 
                       

30


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(13) Business Segments
The Company has two reportable segments: oil and gas exploration and production (“Oil and Gas”) and drilling and trucking operations (“Drilling”) through its ownership in DHS. Following is a summary of segment results for the three and nine months ended September 30, 2010 and 2009:
                                 
                  Inter-segment        
    Oil and Gas     Drilling     Eliminations     Consolidated  
    (In thousands)  
Three Months Ended September 30, 2010
                               
Revenues from external customers
  $ 20,232     $ 15,204     $     $ 35,436  
Inter-segment revenues
                       
 
                       
Total revenues
  $ 20,232     $ 15,204     $     $ 35,436  
 
                               
Operating loss
  $ (11,836 )   $ (4,110 )   $     $ (15,946 )
 
                               
Other income (expense)
    (442 )     (2,288 )           (2,730 )
 
                       
Loss from continuing operations, before tax
  $ (12,278 )   $ (6,398 )   $     $ (18,676 )
 
                       
 
                               
Three Months Ended September 30, 2009
                               
Revenues from external customers
  $ 18,909     $ 2,538     $     $ 21,447  
Inter-segment revenues
          51       (51 )      
 
                       
Total revenues
  $ 18,909     $ 2,589     $ (51 )   $ 21,447  
 
                               
Operating loss
  $ (74,043 )   $ (6,765 )   $ 22     $ (80,786 )
 
                               
Other income (expense)
    (13,995 )     (1,498 )           (15,493 )
 
                       
Loss from continuing operations, before tax
  $ (88,038 )   $ (8,263 )   $ 22     $ (96,279 )
 
                       
 
                               
Nine Months Ended September 30, 2010
                               
Revenues from external customers
  $ 74,195     $ 36,200     $     $ 110,395  
Inter-segment revenues
          795       (795 )      
 
                       
Total revenues
  $ 74,195     $ 36,995     $ (795 )   $ 110,395  
 
                               
Operating loss
  $ (67,111 )   $ (11,935 )   $ (118 )   $ (79,164 )
 
                               
Other income (expense)
    469       (6,269 )           (5,800 )
 
                       
Loss from continuing operations, before tax
  $ (66,642 )   $ (18,204 )   $ (118 )   $ (84,964 )
 
                       
 
                               
Nine Months Ended September 30, 2009
                               
Revenues from external customers
  $ 87,840     $ 9,425     $     $ 97,265  
Inter-segment revenues
          2,984       (2,984 )      
 
                       
Total revenues
  $ 87,840     $ 12,409     $ (2,984 )   $ 97,265  
 
                               
Operating loss
  $ (195,794 )   $ (27,598 )   $ (583 )   $ (223,975 )
 
                               
Other income (expense)
    (64,806 )     (5,459 )           (70,265 )
 
                       
Loss from continuing operations, before tax
  $ (260,600 )   $ (33,057 )   $ (583 )   $ (294,240 )
 
                       
 
                               
September 30, 2010:
                               
Total Assets
  $ 1,137,370     $ 77,650     $ (68,665 )   $ 1,146,355  
 
                       
 
                               
December 31, 2009:
                               
Total Assets
  $ 1,440,529     $ 104,287     $ (87,331 )   $ 1,457,485  
 
                       
Other income and expense includes interest and financing costs, realized losses on derivative instruments, unrealized gains and losses on derivative instruments, interest income, income and loss from unconsolidated affiliates and other miscellaneous income. Non-controlling interests are included in inter-segment eliminations.

31


Table of Contents

DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Three and Nine Months Ended September 30, 2010 and 2009
(Unaudited)
 
(14) Subsequent Events
On October 28, 2010, the Company paid the second of three installments payable related to its February 2008 acquisition of leasehold interests in the Piceance Basin from EnCana Oil & Gas (USA) Inc. The $100.0 million payment was funded with restricted cash on hand. The remaining $100 million installment is payable on November 1, 2011. This remaining installment is collateralized by a letter of credit that is backed by restricted deposits held by the letter of credit issuer.
On October 29, 2010, $17.75 million of Wapiti Transaction proceeds originally escrowed at closing pending the receipt of third party consents and exercise of rights of first refusals were released from escrow. Of the total amount escrowed, $15.9 million was released on Delta’s behalf and paid directly to JPMorgan to reduce amounts outstanding under the credit facility. The remaining $1.9 million was released to Wapiti because a right of first refusal held by a third party was exercised. The sale of the right of first refusal properties to the third party was consummated on October 26, 2010, at which time Delta received sales proceeds of $1.9 million, before normal and customary purchase price adjustments.

32


Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”).
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “propose,” “potential,” “predict,” “forecast,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Except for statements of historical or present facts, all other statements contained in this Quarterly Report on Form 10-Q are forward-looking statements. The forward-looking statements may appear in a number of places and include statements with respect to, among other things: business objectives and strategic plans; our expectations with respect to replacing our existing credit facility with a new credit facility; operating strategies; anticipated borrowing capacity; our expectation that we will have adequate cash from operations, credit facility borrowings and other capital sources to satisfy our obligations under our Second Amended and Restated Credit Agreement, as amended, and to meet future debt service, capital expenditure and working capital requirements; anticipated utilization of joint venture and partnership structures; acquisition and divestiture strategies; completion and drilling program expectations, processes and emphasis; oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues); availability of capital to develop our reserves; estimates of future production of oil and natural gas; marketing of oil and natural gas; expected future revenues and earnings, and results of operations; future capital, development and exploration expenditures (including the amount and nature thereof); nonpayment of dividends; expectations regarding competition and our competitive advantages; impact of the adoption of new accounting standards and our financial and accounting systems and analysis programs; anticipated compliance with and impact of laws and regulations; and effectiveness of our internal control over financial reporting.
These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. In some cases, information regarding certain important factors that could cause actual results to differ materially from any forward-looking statement appears together with such statement. In addition, the factors described under “Risk Factors” in our annual report on Form 10-K, as well as other possible factors not listed, could cause actual results to differ materially from those expressed in forward-looking statements, including, without limitation, the following:
   
deviations in and volatility of the market prices of both crude oil and natural gas produced by us;
 
   
the availability of capital on an economic basis, or at all, to fund our required payments under our Second Amended and Restated Credit Agreement, as amended, our working capital needs, and drilling and leasehold acquisition programs, including through potential joint ventures and asset monetization transactions;
 
   
lower natural gas and oil prices negatively affecting our ability to borrow or raise capital, or enter into joint venture or similar industry arrangements and potentially requiring accelerated repayment of amounts borrowed under our revolving credit facility;
 
   
declines in the values of our natural gas and oil properties resulting in write-downs;
 
   
the availability of borrowings under our credit facility and the ability to obtain a new or replacement credit facility;

33


Table of Contents

   
the impact of current economic and financial conditions on our ability to raise capital;
 
   
the over-supply of natural gas in the U.S. as a result of aggressive development activity;
 
   
a contraction in the demand for natural gas in the U.S. as a result of depressed general economic conditions;
 
   
the ability and willingness of our joint venture partners to fund their obligations to pay a portion of our future drilling and completion costs;
 
   
expiration of oil and natural gas leases that are not held by production;
 
   
uncertainties in the estimation of proved reserves and in the projection of future rates of production;
 
   
timing, amount, and marketability of production;
 
   
third party curtailment, or processing plant or pipeline capacity constraints beyond our control;
 
   
our ability to find, acquire, develop, produce and market production from new properties;
 
   
effectiveness of management strategies and decisions;
 
   
the strength and financial resources of our competitors;
 
   
climatic conditions;
 
   
changes in the legal and/or regulatory environment and/or changes in accounting standards policies and practices or related interpretations by auditors or regulatory entities;
 
   
unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
 
   
the timing, effects and success of our acquisitions, dispositions and exploration and development activities;
 
   
our ability to fully utilize income tax net operating loss and credit carry-forwards; and
 
   
the ability and willingness of counterparties to our commodity derivative contracts, if any, to perform their obligations.
Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.
All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements above. Except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.
We caution you not to place undue reliance on these forward-looking statements. We urge you to carefully review and consider the disclosures made in this Form 10-Q and our reports filed with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.

34


Table of Contents

Recent Developments
   
On July 23, 2010, we entered into a definitive Purchase and Sale Agreement with Wapiti Oil & Gas, L.L.C. (“Wapiti”) to sell various non-core assets (the “Wapiti Transaction”) for cash proceeds of $130.0 million. The Wapiti Transaction closed on July 30, 2010 and all amounts escrowed at the original closing pending third party consents or rights of first refusal were received by October 28, 2010.
 
   
Also on July 23, 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) whereby the requisite banks consented to the Wapiti Transaction, subject to specified terms and conditions, including, among others, that the net proceeds from the Wapiti Transaction be used to pay down the balance outstanding under the credit facility and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. Additional amendments to the credit facility are described in Note 7, “Long Term Debt” to the accompanying consolidated financial statements. The proceeds from the Wapiti Transaction allowed us to substantially reduce our outstanding debt and when combined with the post-Wapiti Transaction borrowing base, provide the liquidity necessary to fund our third and fourth quarter 2010 development plan. There are no scheduled or special borrowing base redeterminations before the maturity of the facility in January 2011 and thus we anticipate having adequate liquidity to fund operations. As noted below, we are in the process of refinancing the existing credit facility.
 
   
On April 1, 2010, DHS Drilling Company (“DHS”), the Company’s 49.8% subsidiary, amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants.
2010 Overview
Beginning in November 2009, we were engaged with Morgan Stanley and Evercore Partners to analyze various alternatives to enhance stockholder value, including a sale of some or all of our assets, entering into partnerships or joint ventures, or the sale of the entire company.
As a result of the strategic process described above, on July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti. In conjunction with the completion of this transaction, we repaid $108.5 million of amounts borrowed under our credit facility, our credit facility borrowing base was reduced to $35.0 million and capital expenditure limitations under the credit facility for the third and fourth quarters of 2010 were set at $18.0 million and $10.0 million, respectively.
The Wapiti Transaction was a part of a competitive process initiated in conjunction with the strategic alternatives process. This process has been concluded and our focus has returned to creating value with our core assets through operations. The Board of Directors may reevaluate the renewal of the strategic alternatives process at a later time.
Based on current commodity prices, the Wapiti Transaction, and our amended credit facility terms, we intend to focus capital expenditures for the remainder of 2010 on completing nine previously drilled wells and drilling a deeper well to evaluate potential below the Williams Fork formation in the Vega Area. The capital expenditure limitations provided for in conjunction with our borrowing base redetermination are expected to be adequate to allow for the funding of these development plans. Based on this level of development and considering production sold in the Wapiti Transaction, we expect oil and gas equivalent production for the remainder of 2010 to range between 3.25 Bcfe and 3.55 Bcfe. These plans may be adjusted from time to time depending on commodity prices, status of our credit facility refinancing efforts or other factors.

35


Table of Contents

Liquidity and Capital Resources
On July 30, 2010, we completed the $130.0 million sale of certain non-core properties to Wapiti, and paid down $108.5 million of the amount outstanding under our Credit Agreement as discussed below.
On July 23, 2010, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (as amended, the “Credit Agreement”), with JPMorgan Chase Bank, N.A., as agent, and certain of the financial institutions that are party to the Credit Agreement in which, among other changes, the requisite lenders consented to the Wapiti Transaction, subject to specified terms and conditions, including that the net proceeds from the transaction be used to pay down the balance outstanding under the Credit Agreement and that the borrowing base be reduced to $35.0 million upon consummation of the Wapiti Transaction. The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011. In addition, the Fourth Amendment imposed capital expenditures limitations of $18.0 million for the quarter ending September 30, 2010, $10.0 million for the quarter ending December 31, 2010, and $2.0 million for the period from January 1, 2011 to January 15, 2011, provided that any excess of the limitation over the amount of actual expenditures may be carried forward from an earlier specified period to a subsequent specified period. The Fourth Amendment added a maximum cash on hand covenant which limits our cash and cash equivalents to $10.0 million at any time, with any excess above such limit required to be used to pay down borrowings under the credit facility within three business days. Finally, the Fourth Amendment requires cash disbursements for general and administrative expenses to be within a 10% variance of projected general and administrative expenses provided to the lending banks in conjunction with the execution of the Fourth Amendment.
We were in compliance with the financial ratio, capital expenditures, maximum cash and accounts payables covenants under the Credit Agreement at September 30, 2010, and have been, and are in compliance with the additional covenants outlined above through the date hereof.
On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, as described in “Recent Developments” above.
Our accompanying financial statements have been prepared assuming we will continue as a going concern. We experienced a net loss attributable to Delta common stockholders of $148.6 million for the nine months ended September 30, 2010, and as of September 30, 2010 had a working capital deficiency of $85.8 million, including $21.5 million outstanding under Delta’s credit facility which matures on January 15, 2011 and $71.6 million outstanding under DHS’s credit agreement which matures on August 31, 2011. In addition, the holders of our $115.0 million principal amount of 33/4% Senior Convertible Notes due 2037 have the right to require us to purchase all or a portion of such notes on May 1, 2012 (or thereafter on each May 1 in 2017, 2022, 2027 and 2032). The ongoing losses, near term credit maturities, and working capital deficiency raise substantial doubt about our ability to continue as a going concern.
Taking into consideration the assets sold and proceeds received to date as a result of the strategic evaluation process, we will need to raise additional cash or refinance our existing credit facility with new or existing lenders in order to pay our outstanding borrowings under the Credit Agreement which are due January 15, 2011. As such, we expect to replace the existing facility prior to its maturity, although it is expected that the interest terms and covenant requirements will be more expensive and restrictive, respectively, than the current facility’s rates and terms. The initial term of any new credit facility is expected to provide for maturity prior to May 1, 2012, when the holders of our $115.0 million principal amount of 33/4% Senior Convertible Notes have the right to require us to purchase all or a portion of the notes. As a result, it is anticipated that prior to May 1, 2012, we will need to obtain additional capital in order to repay any amounts outstanding under any new credit facility and to purchase any 3 3/4% Senior Convertible Notes required by the holders of such notes to be purchased by us.
We experienced a net loss attributable to Delta common stockholders of $148.6 million for the nine months ended September 30, 2010. During the nine months ended September 30, 2010, we had an operating loss of $79.2 million, net cash used in operating activities of $26.0 million and net cash used in financing activities of $116.6 million.

36


Table of Contents

During the nine months ended September 30, 2010, we had cash provided by investing activities of $94.8 million, net of $25.0 million invested in oil and gas development activities. At September 30, 2010, we had $14.2 million in cash and remaining availability under the Credit Agreement of approximately $13.5 million, total assets of $1.1 billion and a debt to capitalization ratio of 39.1%. Debt, excluding installments payable on property acquisition which are secured by restricted cash deposits, at September 30, 2010 totaled $350.2 million, comprised of $93.1 million of bank debt ($21.5 million of our indebtedness under our Credit Agreement and $71.6 million of DHS credit facility indebtedness, all of which is classified as current in the accompanying consolidated financial statements), $149.7 million of senior notes and $107.4 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to their stated amount due of $115.0 million.
As of October 29, 2010, our corporate rating and senior unsecured debt rating were Caa3 and Ca, respectively, as issued by Moody’s Investors Service. Moody’s outlook was “negative.” As of October 29, 2010, our corporate credit and senior unsecured debt ratings were CCC and CCC, respectively, as issued by Standard and Poor’s (“S&P”). S&P’s outlook on its rating was “negative.”
Other than in connection with the refinancing and repayment of our debt as discussed above, our future cash requirements are largely dependent upon the number and timing of projects included in our capital development plan, most of which are discretionary. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, through cash provided by operating activities, sales of oil and gas properties, and through borrowings under our credit facility.
The prices we receive for future oil and natural gas production and the level of production have a significant impact on our operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production and the success of our exploration and development activities in generating additional production.
There can be no assurance that the actions undertaken by us will be sufficient to repay the obligations under our credit facility, or, if not, or if additional defaults occur under that facility, that the lenders will be willing to waive further defaults or amend the facility. Although our current level of borrowing capacity under the Credit Agreement is expected to remain the same through maturity because the Fourth Amendment provided that no scheduled or special redetermination will occur prior to the maturity of the facility, there can be no assurance that our current level of borrowing capacity will be maintained under a new credit agreement, or in the event that we are unable to consummate a new facility, that we will be successful in negotiating an extension to the Credit Agreement, or a replacement thereto, upon its scheduled maturity in January 2011. There can similarly be no assurance that DHS will be successful in negotiating an extension to the DHS credit facility, or a replacement thereto, upon its scheduled maturity in August 2011. In addition, there can be no assurance that results of operations and other sources of liquidity, including asset sales, will be sufficient to meet contractual, operating and capital obligations. Our financial statements do not include any adjustments that might result from the outcome of uncertainty regarding our ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet our obligations or to continue as a going concern.
We continue to examine additional sources of long-term capital (including a restructured debt facility, the issuance of debt instruments, sales of assets and joint venture financing), as well as other potential corporate transactions. The availability of additional sources of capital, which will impact our ability to execute our operating strategy and meet our liquidity challenges, will depend upon a number of factors, many of which are beyond our control.

37


Table of Contents

Results of Operations
The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2010 and 2009. This analysis should be read in conjunction with our consolidated financial statements and the accompanying notes thereto included in this Form 10-Q.
Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009
Net Income (Loss) Attributable to Delta Common Stockholders. Net income attributable to Delta common stockholders was $13.9 million, or $0.05 per diluted common share, for the three months ended September 30, 2010, compared to a net loss attributable to Delta common stockholders of $96.8 million, or $0.35 per diluted common share, for the three months ended September 30, 2009. There were a number of items affecting comparability between periods including contract drilling and trucking fees and expenses, impairments, depletion expense, and unrealized gains and losses on derivative instruments. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.
Oil and Gas Sales. During the three months ended September 30, 2010, oil and gas sales increased 6% to $20.2 million, as compared to $19.1 million for the comparable period a year earlier. The increase was principally the result of a 79% increase in natural gas prices and a 12% increase in oil prices, partially offset by a 23% decrease in production. The average natural gas price received during the three months ended September 30, 2010 increased to $4.52 per Mcf compared to $2.52 per Mcf for the year earlier period. The average oil price received during the three months ended September 30, 2010 increased to $69.13 per Bbl compared to $61.89 per Bbl for the year earlier period. The production decrease was primarily related to lower volumes as a result of the sale to Wapiti.
Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the three months ended September 30, 2010 increased to $15.2 million compared to $2.5 million in the prior year. The increase is the result of improved third party rig utilization in the three months ended September 30, 2010 resulting from an increased industry demand attributable to improved commodity prices.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the three months ended September 30, 2010 and 2009 are as follows:
                 
    Three Months Ended
    September 30,
    2010   2009
Production — Continuing Operations:
               
Oil (Mbbl)
    116       171  
Gas (Mmcf)
    2,694       3,370  
Total Production (Mmcfe) — Continuing Operations
    3,392       4,396  
 
               
Average Price — Continuing Operations:
               
Oil (per barrel)
  $ 69.13     $ 61.89  
Gas (per Mcf)
  $ 4.52     $ 2.52  
 
               
Costs (per Mcfe) — Continuing Operations:
               
Lease operating expense
  $ 1.76     $ 1.55  
Transportation expense
  $ 1.00     $ 0.46  
Production taxes
  $ 0.29     $ 0.16  
Depletion expense
  $ 4.02     $ 4.40  
 
               
Realized derivative gains (losses) (per Mcfe)
  $ (0.12 )   $ 0.08  

38


Table of Contents

Lease Operating Expense. Lease operating expenses for the three months ended September 30, 2010 decreased to $6.0 million from $6.8 million in the year earlier period primarily due to lower water handling costs in the Vega area as a result of the resumption of development activities and due to the Wapiti sale. Lease operating expense per Mcfe for the three months ended September 30, 2010 increased to $1.76 per Mcfe from $1.55 per Mcfe. The quarter-over-quarter increase on a per unit basis was primarily due to the effect of fixed costs spread over a 23% decline in production volumes.
Transportation Expense. Transportation expense for the three months ended September 30, 2010 increased to $3.4 million from $2.0 million in the prior year. Transportation expense per Mcfe for the three months ended September 30, 2010 increased 117% to $1.00 per Mcfe from $0.46 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Production Taxes. Production taxes for the three months ended September 30, 2010 were $996,000, as compared to prior year costs of $717,000. Production taxes as a percentage of oil and gas sales were 4.9% and 3.8% for the three months ended September 30, 2010 and 2009, respectively.
Exploration Expense. Exploration expense consists primarily of geological and geophysical costs and delay lease rentals. Our exploration costs for the three months ended September 30, 2010 were $368,000 compared to $891,000 for the comparable year earlier period. Exploration activities in both periods primarily relate to delay rental payments.
Dry Hole Costs and Impairments. We incurred dry hole costs and impairments of $(262,000) for the three months ended September 30, 2010 as a result of minor cost true-ups compared to $53.4 million for the comparable period a year ago. During the three months ended September 30, 2009, dry hole and impairment costs primarily related to $31.0 million of dry hole costs associated with the Gray 31-23 in the Columbia River Basin, $20.4 million of impairments for unproved leaseholds in Columbia River Basin and $1.9 million of impairments for proved leaseholds in Angleton.
Depreciation, Depletion, Amortization and Accretion — Oil and Gas. Depreciation, depletion and amortization expense decreased 28% to $14.4 million for the three months ended September 30, 2010, as compared to $20.1 million for the comparable year earlier period. Depletion expense for the three months ended September 30, 2010 decreased to $13.6 million from $19.3 million for the three months ended September 30, 2009 due to lower production volumes and a decrease in the per unit depletion rate. Our depletion rate decreased from $4.40 per Mcfe for the three months ended September 30, 2009 to $4.02 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties.
Drilling and Trucking Operating Expenses. Drilling expense increased to $12.0 million for the three months ended September 30, 2010 compared to $2.8 million for the comparable prior year period. This increase is due to additional third party rig utilization during the current year period.
Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling and trucking decreased to $4.8 million for the three months ended September 30, 2010, as compared to $5.5 million for the comparable year earlier period. The decrease is due to the effect on the depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.
General and Administrative Expense. General and administrative expense increased 3% to $10.3 million for the three months ended September 30, 2010, as compared to $10.0 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process and $1.4 million of allowance for doubtful accounts recorded by DHS, partially offset by decreased non-cash stock compensation expense related to restricted stock granted in December 2009 and by reduced staffing as a result of reductions in force during the third quarter of 2010 resulting in lower cash compensation expense.

39


Table of Contents

Executive Severance Expense, Net. On July 6, 2010, John Wallace, the then President, Chief Operating Officer and a Director of the Company, resigned from all of his positions as director, officer and employee of the Company and any of its subsidiaries. In conjunction with such resignation, the Company entered into a severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and certain other interests he might claim arising from his efforts in his previous capacities with the Company and its subsidiaries, and (b) make himself reasonably available to answer questions to facilitate an orderly transition. Under the terms of his severance arrangement, the Company paid Mr. Wallace a lump sum of $1,600,000, paid him his salary for the full month in which his resignation occurred and for his accrued vacation days, reimbursed him for his reasonable business expenses incurred through the effective date of the agreement, and agreed to provide to him insurance benefits similar to his pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage under applicable law. The severance agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.3 million of equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period being completed as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.
Interest Expense and Financing Costs, Net. Interest expense and financing costs, net decreased 4% to $9.3 million for the three months ended September 30, 2010, as compared to $9.7 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances coupled with lower interest rates during the third quarter of 2010 as compared to the third quarter of 2009.
Realized Gain (Loss) on Derivative Instruments, Net. During the three months ended September 30, 2010, we recognized a $418,000 loss associated with settlements on derivative contracts. During the three months ended September 30, 2009, we recognized a $370,000 gain associated with settlements on derivative contracts.
Unrealized Gain (Loss) on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $7.1 million of unrealized gains on derivative instruments in other income and expense during the three months ended September 30, 2010 compared to $5.9 million of unrealized losses for the comparable prior year period.
Income (Loss) From Unconsolidated Affiliates. Income (loss) from unconsolidated affiliates during the three months ended September 30, 2010 and 2009 is comprised of our pro-rata share of net income (loss) of our unconsolidated affiliates.
Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense for the three months ended September 30, 2010 and 2009 of $86,000 and $265,000, respectively, relates only to DHS, as no benefit was provided for our net operating losses.

40


Table of Contents

Discontinued Operations. The results of operations and impairment loss relating non-core property interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued operations as a result of the sale to Wapiti. In a separate transaction, during the three months ended September 30, 2010, we sold our interest in the Howard Ranch field which is also included in discontinued operations.
The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the three months ended September 30, 2010 and 2009 (dollar amounts in thousands):
                 
    Three Months Ended  
    September 30,  
    2010     2009  
Production — Discontinued Operations:
               
Oil (Mbbl)
    2       9  
Gas (Mmcf)
    251       688  
Total Production (Mmcfe) — Discontinued Operations
    262       741  
 
               
Revenues
  $ 1,344     $ 2,475  
 
               
Operating expenses:
               
 
               
Lease operating expense
    429       757  
Transportation expense
    181       60  
Production taxes
    116       438  
Depreciation, depletion, amortization and accretion
    33       5,649  
Impairment provision
           
 
           
Total operating expenses
    759       6,904  
 
           
 
               
Income (Loss) from discontinued operations
    585       (4,429 )
Income tax expense
           
 
           
 
               
Income (loss) from results of operations of discontinued properties, net of tax
    585       (4,429 )
 
               
Gain on sale of discontinued operations
    28,910        
 
           
 
               
Total income (loss) from discontinued operations
  $ 29,495     $ (4,429 )
 
           
On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash proceeds of $130.0 million. We recognized a gain on sale for the closing of the Wapiti Transaction in the three months ended September 30, 2010 of $29.6 million. The gain is subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. During the third quarter of 2010, we also sold our Howard Ranch properties for $550,000. We recognized a loss on the sale of $687,000.
Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the three months ended September 30, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

41


Table of Contents

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Net Loss Attributable to Delta Common Stockholders. Net loss attributable to Delta common stockholders was $148.6 million, or $0.54 per diluted common share, for the nine months ended September 30, 2010, compared to a net loss attributable to Delta common stockholders of $294.7 million, or $1.55 per diluted common share, for the nine months ended September 30, 2009. There were a number of items affecting comparability between periods including oil and gas sales, contract drilling and trucking fees and expenses, gain on offshore litigation award, impairments, depletion expense, interest and financial costs, and realized and unrealized gains and losses on derivative instruments. Explanations of significant items affecting comparability between periods are discussed by financial statement caption below.
Oil and Gas Sales. During the nine months ended September 30, 2010, oil and gas sales increased 32% to $74.7 million, as compared to $56.8 million for the comparable period a year earlier. The increase was principally the result of a 95% increase in natural gas prices and a 46% increase in oil prices, partially offset by a 22% decrease in production. The average natural gas price received during the nine months ended September 30, 2010 increased to $5.12 per Mcf compared to $2.62 per Mcf for the year earlier period. The average oil price received during the nine months ended September 30, 2010 increased to $70.16 per Bbl compared to $47.93 per Bbl for the year earlier period.
Contract Drilling and Trucking Fees. Contract drilling and trucking fees for the nine months ended September 30, 2010 increased to $36.2 million compared to $9.4 million for the comparable year earlier period. The increase is the result of improved third party rig utilization in the nine months ended September 30, 2010 compared to the comparable year earlier period, resulting from an increased industry demand attributable to improved commodity prices.
Gain (Loss) on Offshore Litigation Award and Property Sales, Net. During the nine months ended September 30, 2009, we recorded a $31.1 million gain for an offshore litigation award. During the nine months ended September 30, 2010, we recorded a $539,000 loss primarily associated with the divestiture of non-core properties. See Note 4, “Oil and Gas Properties,” to the accompanying financial statements for information regarding our 2010 divestitures.
Production and Cost Information
Production volumes, average prices received and cost per equivalent Mcf for the nine months ended September 30, 2010 and 2009 are as follows:
                 
    Nine Months Ended
    September 30,
    2010   2009
Production — Continuing Operations:
               
Oil (Mbbl)
    413       573  
Gas (Mmcf)
    8,931       11,186  
Total Production (Mmcfe) — Continuing Operations
    11,409       14,624  
 
               
Average Price — Continuing Operations:
               
Oil (per barrel)
  $ 70.16     $ 47.93  
Gas (per Mcf)
  $ 5.12     $ 2.62  
 
               
Costs (per Mcfe) — Continuing Operations:
               
Lease operating expense
  $ 1.83     $ 1.45  
Transportation expense
  $ 0.98     $ 0.45  
Production taxes
  $ 0.33     $ 0.22  
Depletion expense
  $ 3.80     $ 4.16  
 
               
Realized derivative gains (losses) (per Mcfe)
  $ (0.45 )   $ 0.03  

42


Table of Contents

Lease Operating Expense. Lease operating expenses for the nine months ended September 30, 2010 of $20.9 million was comparable to $21.3 million in the year earlier period due in part to the Wapiti sale. Lease operating expense per Mcfe for the nine months ended September 30, 2010 increased to $1.83 per Mcfe from $1.45 per Mcfe for the comparable year earlier period. The increase on a per unit basis was primarily due to the effect of fixed costs spread over a 22% decline in production volumes.
Transportation Expense. Transportation expense for the nine months ended September 30, 2010 increased to $11.2 million from $6.7 million in the prior year. Transportation expense per Mcfe for the nine months ended September 30, 2010 increased to $0.98 per Mcfe from $0.45 per Mcfe. The increase on a per unit basis is primarily the result of changes to our Vega gas marketing contract that went into effect in October 2009 whereby our gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Production Taxes. Production taxes for the nine months ended September 30, 2010 were $3.8 million, comparable to prior year costs of $3.2 million. Production taxes as a percentage of oil and gas sales were 5.0% and 5.6% for the nine months ended September 30, 2010 and 2009, respectively. The decrease in the 2010 percentage was primarily due to a decrease in the effective Colorado severance tax rate.
Exploration Expense. Exploration expense primarily consists of geological and geophysical costs and delay lease rentals. Our exploration costs for the nine months ended September 30, 2010 were $952,000, compared to $2.4 million for the comparable year earlier period. Current period exploration activities primarily relate to delay rental payments, while the 2009 period was related to delay rental payments and seismic acquisition costs.
Dry Hole Costs and Impairments. We incurred dry hole and impairment costs of $30.9 million for the nine months ended September 30, 2010 compared to $161.5 million for the comparable period a year ago. During the nine months ended September 30, 2010, dry hole and impairment costs primarily related to proved property impairments of $991,000 for the Opossum Hollow and Golden Prairie fields, unproved property impairments of $25.5 million for the Columbia River Basin, Hingeline, Howard Ranch, Bull Canyon, Garden Gulch, Delores River and Haynesville shale prospects and a $4.8 million impairment of our Paradox pipeline.
We incurred dry hole costs and impairments of approximately $161.5 million for the nine months ended September 30, 2009 primarily related to $103.6 million of impairments for unproved leaseholds in Garden Gulch, Columbia River Basin, Haynesville, Lighthouse, Newton, Caballos Creek, and Opossum Hollow, $6.5 million of DHS equipment and rigs impairments, $10.5 million of Vega surface acreage impairments, $4.3 million of inventory impairments, $3.1 million of impairments for proved leaseholds, a $1.9 million impairment of our Paradox pipeline and $31.0 million of dry hole costs associated with the Gray 31-23 in the Columbia River Basin.
Depreciation, Depletion, Amortization and Accretion — Oil and Gas. Depreciation, depletion and amortization expense decreased 28% to $45.5 million for the nine months ended September 30, 2010, as compared to $63.0 million for the comparable year earlier period. Depletion expense for the nine months ended September 30, 2010 was $43.3 million compared to $60.8 million for the nine months ended September 30, 2009. Our depletion rate decreased from $4.16 per Mcfe for the nine months ended September 30, 2009 to $3.80 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties and Vega area proved undeveloped reserves added as a result of higher Piceance gas prices.
Drilling and Trucking Operating Expenses. Drilling expense increased to $28.1 million for the nine months ended September 30, 2010 compared to $10.4 million for the comparable prior year period. This increase is due to additional third party rig utilization during the current year period.
Depreciation and Amortization — Drilling and Trucking. Depreciation and amortization expense — drilling decreased to $15.6 million for the nine months ended September 30, 2010, as compared to $17.5 million for the comparable year earlier period. The decrease is due to the effect on the depreciation rate of rig impairments recorded during 2009. Depreciation expense is recorded on a straight line basis and is not impacted by changes in the utilization rate.

43


Table of Contents

General and Administrative Expense. General and administrative expense increased 6% to $33.4 million for the nine months ended September 30, 2010, as compared to $31.5 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process, $1.4 million of allowance for doubtful accounts recorded by DHS and by increased non-cash stock compensation expense, partially offset by reduced staffing as a result of reductions in force during both the first half of 2009 and the third quarter of 2010 resulting in lower cash compensation expense.
Executive Severance Expense, Net. On May 26, 2009, our then Chairman of the Board of Directors and Chief Executive Officer, Roger A. Parker, resigned from Delta. In consideration for Mr. Parker’s resignation and his agreement to (a) relinquish all his rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and any other interests he might claim arising from his efforts as Chairman of our Board of Directors and/or Chief Executive Officer, and (b) stay on as a consultant to facilitate an orderly transition and to assist in certain pending transactions, Delta agreed to pay Mr. Parker $4,700,000 in cash, issue to him 1,000,000 shares of Delta common stock, pay him the aggregate of any accrued unpaid salary, vacation days and reimbursement of his reasonable business expenses incurred through the effective date of the agreement, and provide to him insurance benefits similar to his pre-resignation benefits for a thirty-six month period. The Severance Agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms.
On July 6, 2010, John Wallace, the then President, Chief Operating Officer and a Director of the Company, resigned from all of his positions as director, officer and employee of the Company and any of its subsidiaries. In conjunction with such resignation, the Company entered into a severance agreement with Mr. Wallace pursuant to which he agreed to (a) relinquish certain rights under his employment agreement, his change-in-control agreement, certain stock agreements, bonuses relating to past and pending transactions benefiting Delta, and certain other interests he might claim arising from his efforts in his previous capacities with the Company and its subsidiaries, and (b) make himself reasonably available to answer questions to facilitate an orderly transition. Under the terms of his severance arrangement, the Company paid Mr. Wallace a lump sum of $1,600,000, paid him his salary for the full month in which his resignation occurred and for his accrued vacation days, reimbursed him for his reasonable business expenses incurred through the effective date of the agreement, and agreed to provide to him insurance benefits similar to his pre-resignation benefits for the period in which Mr. Wallace is entitled to receive COBRA coverage under applicable law. The severance agreement also contained mutual releases and non-disparagement provisions, as well as other customary terms. In addition, $2.3 million of equity compensation costs previously recorded in the consolidated financial statements related to performance shares forfeited prior to their derived service period being completed as a result of the severance agreement were reversed and reflected as a reduction of executive severance expense.
Interest Expense and Financing Costs, Net. Interest and financing costs, net decreased 30% to $29.4 million for the nine months ended September 30, 2010, as compared to $41.9 million for the comparable year earlier period. The decrease is primarily related to lower average outstanding Delta and DHS credit facility balances coupled with lower interest rates during 2010 as compared to 2009. The decrease is also related to a greater write-off of unamortized deferred financing costs and waiver fees related to the amendments to our credit facilities in 2009 compared to 2010. In addition, the nine months ended September 30, 2009, included $1.0 million of interest expense related to the repurchase from Tracinda of offshore litigation contingent payment rights and $643,000 for the write off of previously unamortized deferred financing costs related to the DHS credit agreement.
Realized Gain (Loss) on Derivative Instruments, Net. During the nine months ended September 30, 2010, we recognized a $5.1 million loss associated with settlements on derivative contracts. During the nine months ended September 30, 2009, we recognized a $370,000 gain associated with settlements on derivative contracts.
Unrealized Loss on Derivative Instruments, Net. We recognize mark-to-market gains or losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. Accordingly, we recognized $28.1 million of unrealized gains on derivative instruments in other income and expense during the nine months ended September 30, 2010 compared to a loss of $27.0 million for the comparable prior year period.

44


Table of Contents

Income (Loss) From Unconsolidated Affiliates. Loss from unconsolidated affiliates during the nine months ended September 30, 2009 is primarily the result of $3.0 million of impairments recorded related to two of our investments. Income from unconsolidated affiliates during the nine months ended September 30, 2010 is comprised of our pro-rata share of net income of our unconsolidated affiliates.
Income Tax Benefit (Expense). Due to our continued losses, we were required by the “more likely than not” threshold for assessing the realizability of deferred tax assets, to record a valuation allowance for our deferred tax assets beginning with the second quarter of 2007. Our income tax expense (benefit) for the nine months ended September 30, 2010 and 2009 of $564,000 and $(53,000), respectively, relates only to DHS, as no benefit was provided for our net operating losses.
Discontinued Operations. The results of operations and impairment loss relating non-core property interests sold in the Garden Gulch field, Baffin Bay field, and Bull Canyon field as well as our interest in our wholly-owned subsidiary Piper Petroleum have been reflected as discontinued operations as a result of the sale to Wapiti. In a separate transaction, during the three months ended September 30, 2010, the Company sold its interest in the Howard Ranch field which is also included in discontinued operations.
The following table shows the total revenues and expenses included in discontinued operations for the above mentioned oil and gas properties for the nine months ended September 30, 2010 and 2009 (dollar amounts in thousands):
                 
    Nine Months Ended  
    September 30,  
    2010     2009  
Production — Discontinued Operations:
               
Oil (Mbbl)
    14       21  
Gas (Mmcf)
    1,903       2,404  
Total Production (Mmcfe) — Discontinued Operations
    1,987       2,531  
 
               
Revenues
  $ 9,623     $ 8,255  
 
               
Operating expenses:
               
 
               
Lease operating expense
    2,676       3,740  
Transportation expense
    1,459       1,196  
Production taxes
    611       544  
Depreciation, depletion, amortization and accretion
    13,837       19,477  
Impairment provision
    92,162        
 
           
Total operating expenses
    110,745       24,957  
 
           
 
               
Loss from discontinued operations
    (101,122 )     (16,702 )
Income tax expense
           
 
           
 
               
Loss from results of operations of discontinued properties, net of tax
    (101,122 )     (16,702 )
 
               
Gain on sale of discontinued operations
    28,910        
 
           
 
               
Total loss from discontinued operations
  $ (72,212 )   $ (16,702 )
 
           
On July 30, 2010, the Company closed on the sale of non-core properties to Wapiti for cash proceeds of $130.0 million. We recognized a gain on sale for the closing of Wapiti Transaction in the three months ended September 30, 2010 of $29.6 million. The gain is subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. During the third quarter of 2010, we also sold our Howard Ranch properties for $550,000. We recognized a loss on the sale of $687,000.
Non-Controlling Interest. Non-controlling interest represents the minority investors’ proportionate share of the income or loss of DHS in which they hold an interest. During the nine months ended September 30, 2010 and 2009, DHS reported significant losses from low rig utilization rates which resulted in a non-controlling interest credit to earnings.

45


Table of Contents

Historical Cash Flow
Our cash flow from operating activities decreased from $20.2 million for the nine months ended September 30, 2009 to cash used in operating activities of $26.0 million for the nine months ended September 30, 2010. The significant decrease in cash flow is primarily the result of changes in working capital and proceeds from the offshore litigation awarded in 2009 partially offset by higher commodity prices. Our net cash provided by investing activities increased to $94.8 million for the nine months ended September 30, 2010 compared to net cash used in investing activities of $137.2 million for the comparable prior year period primarily due to our significant reduction in drilling and acquisition activity and proceeds from the Wapiti Transaction. Cash provided by financing activities decreased from $62.2 million for the nine months ended September 30, 2009 to cash used in financing activities of $116.6 million for the current year period. During the nine months ended September 30, 2010, we made net bank payments of $114.2 million. During the nine months ended September 30, 2009, $246.9 million of cash was received from the issuance of stock and we made net bank payments of $182.0 million.
Capital and Exploration Expenditures
Our capital and exploration expenditures for the nine months ended September 30, 2010 and 2009 were as follows (in thousands):
                 
    2010     2009  
CAPITAL AND EXPLORATION EXPENDITURES:
               
 
               
Property acquisitions:
               
Unproved
  $ 388     $ 1,820  
Proved
           
Oil and gas properties
    27,199       51,236  
Drilling and trucking equipment
    2,048       4,139  
Pipeline and gathering systems
    6,895       9,491  
 
           
Total (1)
  $ 36,530     $ 66,686  
 
           
 
1  
Capital expenditures in the table above are presented on an accrual basis. Additions to property and equipment in the consolidated statement of cash flows reflect capital expenditures on a cash basis, when payments are made.
Contractual and Long-term Debt Obligations
7% Senior Unsecured Notes, due 2015
On March 15, 2005, we issued 7% senior unsecured notes for an aggregate amount of $150.0 million which pay interest semi-annually on April 1 and October 1 and mature in 2015. The notes were issued at 99.50% of par and the associated discount is being amortized to interest expense over the term of the notes. The indenture governing the notes contains various restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make certain investments, sell assets, consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries. These covenants may limit management’s discretion in operating our business.
33/4% Senior Convertible Notes, due 2037
On April 25, 2007, we issued $115.0 million aggregate principal amount of 33/4% Senior Convertible Notes due 2037 (the “Notes”) for net proceeds of $111.6 million after underwriters’ discounts and commissions of approximately $3.4 million. The remaining discount will be amortized through May 1, 2012 when the holders of the Notes can first require us to purchase all or a portion of the Notes. The Notes bear interest at a rate of 33/4% per annum, payable semi-annually in arrears, on May 1 and November 1 of each year. Combined with the amortization of debt discount, the Notes have an effective interest rate of approximately 7.8% and 7.6% with total interest costs of $2.2 million for each of the three month periods ended September 30, 2010 and 2009, respectively, and interest costs of $6.6 million and $6.5 million for the nine month periods ended September 30, 2010 and 2009, respectively. The Notes will mature

46


Table of Contents

on May 1, 2037 unless earlier converted, redeemed or repurchased. The holders of the Notes have the right to require us to purchase all or a portion of the Notes on May 1, 2012, May 1, 2017, May 1, 2022, May 1, 2027, and May 1, 2032. The Notes will be convertible at the holder’s option, in whole or in part, at an initial conversion rate of 32.9598 shares of common stock per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $30.34 per share) at any time prior to the close of business on the business day immediately preceding the final maturity date of the Notes, subject to prior repurchase of the Notes. The conversion rate may be adjusted from time to time in certain instances. Upon conversion of a Note, we will have the option to deliver shares of our common stock, cash or a combination of cash and shares of our common stock for the Notes surrendered. In addition, following certain fundamental changes that occur prior to maturity, we will increase the conversion rate for a holder who elects to convert its Notes in connection with such fundamental changes by a number of additional shares of common stock. Although the Notes do not contain any financial covenants, the Notes contain covenants that require us to properly make payments of principal and interest, provide certain reports, certificates and notices to the trustee under various circumstances, cause our wholly-owned subsidiaries to become guarantors of the debt, maintain an office or agency where the Notes may be presented or surrendered for payment, continue our corporate existence, pay taxes and other claims, and not seek protection from the debt under any applicable usury laws.
Credit Facility — Delta
Pursuant to the Fourth Amendment dated as of July 23, 2010, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, the borrowing base under our Credit Agreement was reduced to $35.0 million upon the consummation of the Wapiti Transaction.
The Fourth Amendment eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011.
The Credit Agreement includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and includes various financial covenants.
Under certain conditions, amounts outstanding under the credit facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of our subsidiaries would result in an automatic acceleration of the indebtedness under the credit facility. Subject to notice and cure periods in certain cases, other events of default under the credit facility would result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.
This facility is secured by a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, and oil and gas inventory.
Credit Facility — DHS
On April 1, 2010 DHS amended its existing credit facility with Lehman Commercial Paper, Inc. and renegotiated certain terms of the agreement, to, among other changes more fully described in Note 7, “Long Term Debt” to the accompanying financial statements, bring DHS into compliance with the terms of the agreement, amend the principal repayment schedule, adjust the interest rate, and eliminate or amend certain financial covenants.
Other Contractual Obligations
Our asset retirement obligation arises from the costs necessary to plug and abandon our oil and gas wells. The majority of the expenditures related to this obligation will not occur during the next five years.
We lease our corporate office in Denver, Colorado under an operating lease which will expire in 2014. Our average yearly payments approximate $1.3 million over the term of the lease. We have additional operating lease

47


Table of Contents

commitments which represent office equipment leases and lease obligations primarily relating to field vehicles and equipment.
We had a net derivative asset of $1.1 million at September 30, 2010. The ultimate settlement amounts of these derivative instruments are unknown because they are subject to continuing market fluctuations. See Item 3. “Quantitative and Qualitative Disclosures about Market Risk” for more information regarding our derivative instruments.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations were based on the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 3 to our consolidated financial statements. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.
Successful Efforts Method of Accounting
We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within an oil and gas field are typically considered development costs and are capitalized, but often these seismic programs extend beyond the reserve area considered proved, and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

48


Table of Contents

Reserve Estimates
Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, the availability and cost of capital to develop the reserves, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Impairment of Gas and Oil Properties
We review our oil and gas properties for impairment quarterly or whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and production costs, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. For proved properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. For the nine months ended September 30, 2010, the expected future undiscounted cash flows of the assets exceeded the carrying value of the corresponding asset and as such no impairment provision was recognized.
For unproved properties, the need for an impairment charge is based on our plans for future development and other activities impacting the life of the property and our ability to recover our investment. When we believe the costs of the unproved property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property.
As a result of such assessment, we recorded impairment provisions attributable to unproved properties of $22.5 million for the nine months ended September 30, 2010. The $22.5 million impairment included $11.4 million related to our Columbia River Basin leasehold, $5.0 million related to our Hingeline leasehold, $3.8 million related to our Haynesville leasehold, $1.6 million related to our Delores River leasehold and $661,000 related to our Howard Ranch leasehold. In addition, we recorded an impairment of $4.8 million to reduce the Paradox pipeline carrying value to its estimated fair value during the nine months ended September 30, 2010. These impairments are included within dry hole costs and impairments in the accompanying statement of operations for the nine months ended September 30, 2010.

49


Table of Contents

In addition to the impairment provisions discussed above, we utilized various fair value techniques related to our Garden Gulch, Baffin Bay, DJ Basin, Caballos Creek, Opossum Hollow, Midway Loop, and Newton fields, as well as our interest in our wholly owned subsidiary Piper Petroleum and unproved acreage positions in the DJ Basin and South Texas assets which were held for sale at June 30, 2010 and determined that impairment provisions of $93.2 million related to proved properties and $3.0 million related to unproved properties were required to be recognized during the three months ended June 30, 2010. Based upon the applicable accounting standards, $4.0 million of the impairment provision is included within dry hole costs and impairments in the accompanying statement of operations for the nine months ended September 30, 2010 and $92.2 million is included in loss from discontinued operations for the nine months ended September 30, 2010.
During the remainder of 2010, we are continuing to evaluate certain proved and unproved properties on which favorable or unfavorable results or fluctuations in commodity prices may cause us to revise in future periods our estimates of future cash flows from those properties. Such revisions of estimates could require us to record an impairment provision in the period of such revisions.
Commodity Derivative Instruments and Hedging Activities
We may periodically enter into commodity derivative contracts or fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize futures contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe represent minimal credit risks.
All derivative instruments are recorded on the balance sheet at fair value which must be estimated using complex valuation models. We recognize mark-to-market gains and losses in current earnings instead of deferring those amounts in accumulated other comprehensive income. As of September 30, 2010, we had a total of seven oil and gas derivative contracts outstanding. The fair value of our oil derivative instruments was a liability of $7.0 million and the fair value of our gas derivative instruments was an asset of $8.1 million at September 30, 2010. We classify the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, whichever the case may be, by commodity and master netting counterparty. The discount rates used to determine the fair value of these derivative instruments include a measure of non-performance risk by both Delta and the counterparty, and accordingly, the liability reflected is less than the actual cash expected to be paid upon settlement based on forward prices as of September 30, 2010. The pre-credit risk adjusted fair value of our net derivative assets as of September 30, 2010 was $617,000. A credit risk adjustment of $483,000 to the fair value of the derivatives caused the reported amount of the net derivative assets on our consolidated balance sheet to be $1.1 million.
Asset Retirement Obligation
We account for our asset retirement obligations under applicable FASB guidance which requires entities to record the fair value of a liability for retirement obligations of acquired assets. Our asset retirement obligations arise from the plugging and abandonment liabilities for our oil and gas wells. The fair value is estimated based on a variety of assumptions including discount and inflation rates and estimated costs and timing to plug and abandon wells.
Deferred Tax Asset Valuation Allowance
The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive

50


Table of Contents

evidence. As a result of management’s current assessment, we maintain a significant valuation allowance against our deferred tax assets. We will continue to monitor facts and circumstances in our reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, we may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense or benefit.
Recently Issued and Adopted Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”), which provides amendments to FASB ASC Topic 820, Fair Value Measurements and Disclosures. The objective of ASU 2010-06 is to provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 is effective for fiscal years and interim periods beginning after December 15, 2009. We adopted ASU 2010-06 effective January 1, 2010, which did not have an impact on our consolidated financial statements, other than additional disclosures.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market Rate and Price Risk
We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, which may from time to time include costless collars, swaps, or puts. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices and our operating strategy. We use hedges to limit the risk of fluctuating cash flows that fund our capital expenditure program. We also may use hedges in conjunction with acquisitions to achieve expected economic returns during the payout period.
The following table summarizes our open derivative contracts at September 30, 2010:
                                                
                                    Net Fair Value  
                        Remaining       Asset (Liability) at  
Commodity   Volume   Fixed Price     Term   Index Price   September 30, 2010  
                                    (In thousands)  
Crude oil
    1,000     Bbls / Day1   $ 52.25     Oct ’10 - Dec ’10   NYMEX — WTI   $ (2,600 )
Crude oil
    500     Bbls / Day   $ 57.70     Jan ’11 - Dec ’11   NYMEX — WTI     (4,404 )
Natural gas
    6,000     MMBtu / Day   $ 5.720     Oct ’10 - Dec ’10   NYMEX — HHUB     977  
Natural gas
    15,000     MMBtu / Day   $ 4.105     Oct ’10 - Dec ’10   CIG     705  
Natural gas
    5,367     MMBtu / Day   $ 3.973     Oct ’10 - Dec ’10   CIG     187  
Natural gas
    12,000     MMBtu / Day   $ 5.150     Jan ’11 - Dec ’11   CIG     5,006  
Natural gas
    3,253     MMBtu / Day   $ 5.040     Jan ’11 - Dec ’11   CIG     1,229  
 
                                     
 
                                  $ 1,100  
 
                                     
 
1  
As a result of the closing of the Wapiti Transaction, for the period from October to December 2010, derivative contract volumes were anticipated to exceed physical production volumes in certain months. Accordingly, in October 2010, the Company partially terminated its November and December 2010 derivatives for a cost of $729,000 to reduce the hedged volume from 1,000 barrels per day to 625 barrels per day.
Assuming production and the percent of oil and gas sold remained unchanged for the nine months ended September 30, 2010, a hypothetical 10% decline in the average market price we realized during the nine months ended September 30, 2010 on unhedged production would reduce our oil and natural gas revenues by approximately $7.5 million.
Interest Rate Risk
We were subject to interest rate risk on $93.1 million of variable rate debt obligations at September 30, 2010. The annual effect of a 10% change in interest rates on the debt would be approximately $716,000.

51


Table of Contents

Item 4. Controls and Procedures
Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act. Based on this evaluation, our management, including our principal executive officer and our principal financial officer, concluded that our disclosure controls and procedures were effective as of September 30, 2010, to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act (i) is recorded, processed, summarized and reported within the time period specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow appropriate decisions on a timely basis regarding required disclosure.
Internal Control over Financial Reporting
There were no changes in internal control over financial reporting that occurred during the fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows, except as follows:
We are currently engaged in arbitration with 212 Resources Corporation (“212”) with regard to a dispute involving a May 18, 2008 Oil and Gas Fluid Processing Agreement (the “Agreement”) between 212 and us. The Agreement requires 212 to design, construct, and operate “Mobile Pods” to treat and discharge to surface waters fluid produced by our oil and gas operations in compliance with applicable law and permits, and requires us to pay 212 approximately $500,000 per month commencing on the earlier of the date that such Mobile Pod is (a) first Available, or (b) first used to provide the contemplated services. The term “Available,” as used in the Agreement, means the first date that a Mobile Pod is mechanically capable of providing the contemplated services (or would have been mechanically capable of providing such services but for our failure to perform any of our obligations under the Agreement). On October 27, 2009, 212 filed a Demand for Arbitration and Statement of Claim and alleged that we delayed the performance of our duty to obtain permits and construct the site under the Agreement. 212 contends, in essence, that we delayed obtaining permits for the operation of the Mobile Pods and that we owe the monthly fee for the Mobile Pods for the period commencing on October 1, 2009. We have denied 212’s claims and contend, in essence, that 212 has still not demonstrated that the Mobile Pods are capable of treating and discharging to surface waters fluid produced by our oil and gas operations in compliance with applicable law and permits. We have also filed counterclaims. The matter is currently set for arbitration on November 29, 2010, but we have filed a motion seeking a delay of the hearing for a time sufficient to obtain and analyze a variety of test results to determine whether or not the operation of the Mobile Pods complies with applicable law and permits. While we believe that we have meritorious defenses to 212’s claims and have valid counterclaims, we are unable to predict the ultimate outcome of the arbitration.
The Company’s indirect, 49.8% owned affiliate DHS Drilling Company (“DHS”) and certain of its employees, among others, have been notified by the Office of the Inspector General, Office of Investigations, of the Export-Import Bank of the United States, and the U.S. Department of Justice, that they are the subject of an investigation in connection with a loan guarantee sought from the Export-Import Bank in the first quarter of 2010 of a loan from a Mexican bank to a DHS customer in Mexico. DHS has cooperated and will continue to cooperate with the investigation, which is currently in its initial stages. This investigation is subject to uncertainties, and, as such, DHS is unable to estimate the nature of any possible liability that may result.

52


Table of Contents

Item 1A. Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock, senior notes or convertible notes are described below and under “Risk Factors” in Item 1A of our 2009 Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on March 12, 2010. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
Our existing credit facility matures on January 15, 2011 and we may be unable to refinance in a timely manner or on terms acceptable to us, if at all.
Our existing credit facility matures on January 15, 2011, at which time all amounts outstanding thereunder will be due and payable. Without a refinancing of the credit facility or another capital-raising transaction, management currently does not believe that we will have sufficient cash on hand, based on current cash flow projections, to repay the credit facility in full at maturity. We are currently negotiating with a new lender to replace our existing credit facility, but there can be no assurance that we will be able to refinance the credit facility on terms and conditions acceptable to us, or at all, or on a timely basis. In addition, credit or financial market disruptions such as those that have recently been experienced in the United States and abroad may have a material adverse effect on our ability to refinance the credit facility on a timely basis and on terms acceptable to us, if at all. Without a replacement credit facility, it is likely that we will have limited borrowing capacity and insufficient capital to support our development and capital expenditure plans.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The table below provides a summary of our purchases of our own common stock during the three months ended September 30, 2010.
                                 
                            Maximum Number  
                    Total Number of     (or Approximate Dollar  
                    Shares (or Units)     Value) of Shares  
    Total Number of     Average Price     Purchased as Part of     (or Units) that May Yet  
    Shares (or Units)     Paid Per Share     Publicly Announced     Be Purchased Under  
Period   Purchased (1)     (or Unit) (2)     Plans or Programs (3)     the Plans or Programs (3)  
July 1 – July 31, 2010
    903,000     $ 0.82              
August 1 – August 31, 2010
                       
September 1 – September 30, 2010
                       
 
                       
Total
    903,000     $ 0.82              
 
                       
 
(1)  
Consists of shares delivered back to us by employees and/or directors to satisfy tax withholding obligations that arise upon the vesting of the stock awards. We, pursuant to our equity compensation plans, give participants the opportunity to turn back to us the number of shares from the award sufficient to satisfy the person’s tax withholding obligations that arise upon the termination of restrictions.
 
(2)  
The stated price does not include any commission paid.
 
(3)  
These sections are not applicable as we have no publicly announced stock repurchase plans.
Item 5. Other Information
None.

53


Table of Contents

Item 6. Exhibits.
Exhibits are as follows:
  10.1  
Severance Agreement by and between Delta Petroleum Corporation and John R. Wallace, effective October 19, 2010. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed October 25, 2010.
 
  31.1  
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
 
  31.2  
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
 
  32.1  
Certification of principal executive officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.
 
  32.2  
Certification of principal financial officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

54


Table of Contents

SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  DELTA PETROLEUM CORPORATION
(Registrant)
 
 
  By:   /s/ Carl E. Lakey    
    Carl E. Lakey, President and   
    Chief Executive Officer   
 
     
  By:   /s/ Kevin K. Nanke    
    Kevin K. Nanke, Treasurer and   
    Chief Financial Officer   
 
Date: November 9, 2010

55


Table of Contents

EXHIBIT INDEX:
  10.1  
Severance Agreement by and between Delta Petroleum Corporation and John R. Wallace, effective October 19, 2010. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K filed October 25, 2010.
 
  31.1  
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
 
  31.2  
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
 
  32.1  
Certification of principal executive officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.
 
  32.2  
Certification of principal financial officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.