SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2002 [ ] 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 Petroleum Corporation (Exact name of registrant as specified in its charter) Colorado 84-1060803 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 475 17th Street, Suite 1400 Denver, Colorado 80202 (Address of principal executive offices) (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 X No___ 13,038,000 shares of common stock $.01 par value were outstanding as of May 14, 2002.
FORM 10-Q 3rd QTR. FY 2002 INDEX PART I FINANCIAL INFORMATION PAGE NO. Item 1. Consolidated Financial Statements Consolidated Balance Sheets - March 31, 2002 and June 30, 2001 (unaudited)...................................1 Consolidated Statements of Operations - Three Months Ended March 31, 2002 and 2001 (unaudited).........................3 Consolidated Statements of Operations - Nine Months Ended March 31, 2002 and 2001 (unaudited).........................4 Consolidated Statement of Stockholders' Equity and Comprehensive Income (loss) Year Ended June 30, 2001 and Nine Months Ended March 31, 2002 (unaudited)................5 Consolidated Statements of Cash Flows - Nine Months Ended March 31, 2002 and 2001 (unaudited).........................6 Notes to Consolidated Financial Statements (unaudited)......7 Item 2. Management's Discussion and Analysis Or Plan of Operations.......................................19 Item 3. Market Risk.................................................29 PART II OTHER INFORMATION Item 1. Legal Proceedings...........................................30 Item 2. Changes in Securities.......................................30 Item 3. Defaults upon Senior Securities.............................31 Item 4. Submission of Matters to a Vote of Security Holders............................................31 Item 5. Other Information...........................................31 Item 6. Exhibits and Reports on Form 8-K............................31 The terms "Delta", "Company", "we", "our", and "us" refer to Delta Petroleum Corporation unless the context suggests otherwise. i
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS - ----------------------------------------------------------------------------- March 31, June 30, 2002 2001 ------------ ----------- (Unaudited) ASSETS Current Assets: Cash $ 274,000 $ 518,000 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 at March 31, 2002 and June 30, 2001 824,000 1,673,000 Accounts receivable - related parties 118,000 272,000 Prepaid assets 953,000 594,000 Other current assets 222,000 538,000 ----------- ----------- Total current assets 2,391,000 3,595,000 ----------- ----------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting): 27,829,000 29,955,000 Less accumulated depreciation and depletion (5,267,000) (5,024,000) ----------- ----------- Net property and equipment 22,562,000 24,931,000 ----------- ----------- Long term assets: Deferred financing costs 147,000 241,000 Investment in Bion Environmental 112,000 221,000 Partnership net assets 916,000 844,000 Assets held for sale 5,702,000 - ----------- ----------- Total long term assets 6,877,000 1,306,000 $31,830,000 $29,832,000 =========== =========== 1
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS, CONTINUED - ----------------------------------------------------------------------------- March 31, June 30, 2002 2001 ------------ ----------- (Unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current portion of long-term debt $ 3,186,000 $ 3,038,000 Accounts payable 2,626,000 2,071,000 Other accrued liabilities 45,000 46,000 ----------- ----------- Total current liabilities 5,857,000 5,155,000 ----------- ----------- Long-term debt, net 4,934,000 6,396,000 ----------- ----------- Stockholders' Equity: Preferred stock, $.10 par value; authorized 3,000,000 shares, none issued - - Common stock, $.01 par value; authorized 300,000,000 shares, issued 11,424,000 shares at March 31, 2002 and 13,038,000 at June 30, 2001 130,000 112,000 Additional paid-in capital 47,042,000 40,700,000 Accumulated other comprehensive income (40,000) 69,000 Accumulated deficit (26,093,000) (22,600,000) ----------- ----------- Total stockholders' equity 21,039,000 18,281,000 ----------- ----------- Commitments $31,830,000 $29,832,000 =========== =========== See accompanying notes to consolidated financial statements. 2
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - ----------------------------------------------------------------------------- Three Months Ended March 31, March 31, 2002 2001 ----------- ----------- Revenue: Oil and gas sales $ 1,138,000 $ 3,661,000 Operating fee income 27,000 26,000 Loss on sale of oil and gas properties (107,000) - Other revenue - 15,000 ----------- ----------- Total revenue 1,058,000 3,702,000 Operating expenses: Lease operating expenses 865,000 1,520,000 Depreciation and depletion 587,000 600,000 Exploration expenses 16,000 26,000 Dry hole costs 15,000 90,000 Abandoned and impaired properties - - Professional fees 284,000 348,000 General and administrative 593,000 268,000 Stock option expense 20,000 45,000 ----------- ----------- Total operating expenses 2,380,000 2,897,000 ----------- ----------- Income from operations (1,322,000) 805,000 Other income and expenses: Other income 9,000 30,000 Interest and financing costs (274,000) (504,000) ----------- ----------- Total other income and expenses (265,000) (474,000) ----------- ----------- Net income (loss) $(1,587,000) $ 331,000 =========== =========== Net income (loss) per common share: Basic $ (0.13) $ 0.03 =========== =========== Diluted $ (0.13)* $ 0.02 =========== =========== * Potentially dilutive securities outstanding were anti-dilutive See accompanying notes to consolidated financial statements. 3
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - ----------------------------------------------------------------------------- Nine Months Ended March 31, March 31, 2002 2001 ----------- ----------- Revenue: Oil and gas sales $ 5,317,000 $ 9,352,000 Operating fee income 80,000 80,000 Loss on sale of oil and gas properties (107,000) - Other revenue - 77,000 ----------- ----------- Total revenue 5,290,000 9,509,000 Operating expenses: Lease operating expenses 2,679,000 3,783,000 Depreciation and depletion 2,249,000 1,556,000 Exploration expenses 125,000 49,000 Dry hole costs 396,000 90,000 Abandoned and impaired properties 162,000 - Professional fees 954,000 815,000 General and administrative 1,231,000 896,000 Stock option expense 53,000 334,000 ----------- ----------- Total operating expenses 7,849,000 7,523,000 ----------- ----------- Income from operations (2,559,000) 1,986,000 Other income and expenses: Other income 13,000 402,000 Interest and financing costs (947,000) (1,495,000) ----------- ----------- Total other income and expenses (934,000) (1,093,000) ----------- ----------- Net income (loss) $(3,493,000) $ 893,000 =========== =========== Net income (loss) per common share: Basic $ (0.30) $ 0.09 =========== =========== Diluted $ (0.30)* $ 0.08 =========== =========== * Potentially dilutive securities outstanding were anti-dilutive See accompanying notes to consolidated financial statements. 4
DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss) Year ended June 30, 2001 and Nine Months Ended March 31, 2002 (Unaudited) - ----------------------------------------------------------------------------- <TABLE> <CAPTION> Accumulated other compre- Common Stock Additional hensive ----------------- paid-in income Comprehensive Accumulated Shares Amount capital (loss) income (loss) deficit Total ---------- -------- ---------- --------- ------------- ------------ ------------ <S> <C> <C> <C> <C> <C> <C> <C> Balance, July 1, 2000 8,422,000 $ 84,000 33,747,000 77,000 (22,945,000) 10,963,000 Comprehensive loss: Net loss - - - 345,000 345,000 345,000 ----------- Other comprehensive loss, net of tax Unrealized gain on equity securities - - - (8,000) (8,000) (8,000) ----------- Comprehensive loss - - - 337,000 =========== Stock options granted as compensation - - 520,000 - - 520,000 Fair value of warrants issued for common stock investment agreement - - 1,436,000 - - 1,436,000 Warrant issued in exchange for common stock investment agreement - - (1,436,000) - - (1,436,000) Shares issued for cash, net of commissions 1,004,000 10,000 2,412,000 - - 2,422,000 Shares issued for cash upon exercise of options 922,000 9,000 1,471,000 - - 1,480,000 Conversion of note payable and accrued interest to common stock 200,000 2,000 509,000 - - 511,000 Shares issued for oil and gas properties 851,000 9,000 2,945,000 - - 2,954,000 Shares reacquired and retired (239,000) (2,000) (904,000) - - (906,000) ---------- -------- ---------- --------- ------------ ----------- Balance, June 30, 2001 11,160,000 112,000 40,700,000 69,000 (22,600,000) 18,281,000 Comprehensive loss: Net loss - - - (3,493,000) (3,493,000) (3,493,000) ----------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - (109,000) (109,000) (109,000) ----------- Comprehensive income - - - (3,602,000) =========== Stock options granted as compensation - - 53,000 - - 53,000 Shares issued for cash, net of commissions 72,000 1,000 224,000 - - 225,000 Shares issued for cash upon exercise of options 252,000 2,000 397,000 - - 399,000 Shares issued for services 14,000 - 48,000 - - 48,000 Shares issued for oil and gas properties 137,000 1,000 374,000 - - 375,000 Shares issued for all outstanding shares of Piper Petroleum Company 1,377,000 14,000 5,220,000 - - 5,234,000 Shares issued for debt 51,000 - 157,000 - - 157,000 Shares reacquired and retired (25,000) - (131,000) - - (131,000) ---------- -------- ---------- --------- ------------ ----------- Balance, March 31, 2002 13,038,000 $130,000 47,042,000 (40,000) (26,093,000) 21,039,000 ========== ======== ========== ========= ============ =========== </TABLE> See accompanying notes to consolidated financial statements. 5
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - ----------------------------------------------------------------------------- <TABLE> <CAPTION> Nine Months Ended March 31, March 31, 2002 2001 ----------- ----------- <S> <C> <C> Cash flows operating activities: Net income (loss) $(3,493,000) $ 893,000 Adjustments to reconcile net income (loss) to cash used in operating activities: Depreciation and depletion 2,249,000 1,556,000 Stock option expense 53,000 445,000 Amortization of financing costs 417,000 370,000 Abandoned and impaired properties 162,000 - Loss on sale of oil and gas properties 107,000 - Shares issued for services 48,000 - Net changes in operating assets and operating liabilities: (Increase) decrease in trade accounts receivable 897,000 (941,000) Increase in prepaid assets (32,000) (395,000) (Increase) decrease in other current assets (7,000) 61,000 Decrease in accounts payable trade (1,010,000) (120,000) Decrease in other accrued liabilities (1,000) (292,000) Deferred revenue - (44,000) ----------- ----------- Net cash provided by (used in) operating activities $ (546,000) $ 1,533,000 ----------- ----------- Cash flows from investing activities: Additions to property and equipment, net (2,009,000) (9,542,000) Proceeds from sale of oil and gas properties 3,398,000 - Increase in oil and gas properties available for sale (22,000) - Merger with Piper Petroleum 74,000 - (Increase) decrease in long term assets (72,000) 125,000 ----------- ----------- Net cash provided by (used in) investing activities 1,369,000 (9,417,000) ----------- ----------- Cash flows from financing activities: Stock issued for cash upon exercise of options 399,000 994,000 Issuance of common stock for cash 225,000 2,422,000 Proceeds from borrowings 1,633,000 13,520,000 Repayment of borrowings (3,347,000) (8,825,000) Decrease (increase) in accounts receivable from related parties 23,000 (115,000) ----------- ----------- Net cash provided by (used in) financing activities (1,067,000) 7,996,000 ----------- ----------- Net increase (decrease) in cash (244,000) 112,000 ----------- ----------- Cash at beginning of period 518,000 302,000 ----------- ----------- Cash at end of period $ 274,000 $ 414,000 =========== =========== Supplemental cash flow information - Cash paid for interest and financing costs $ 530,000 $ 1,398,000 =========== =========== Non-cash financing activities: Shares issued for all outstanding shares of Piper Petroleum Company $ 5,234,000 $ 906,000 =========== =========== Common stock issued for the purchase of oil and gas properties, net of return of deposited shares $ 375,000 $ 2,832,000 =========== =========== Shares reacquired and retired for oil and gas properties and option exercise $ 131,000 $ 906,000 =========== =========== Common stock issued note payable and accrued interest or accounts payable $ 157,000 $ 511,000 =========== =========== Common stock, options and overriding royalties issued for services relating to debt financing $ - $ 130,000 =========== =========== </TABLE> See accompanying notes to consolidated financial statements. 6 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ----------------------------------------------------------------------------- (1) Basis of Presentation 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 filed with the Company's most recent annual report on Form 10-K/A. 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. 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/A for the year ended June 30, 2001, previously filed with the Securities and Exchange Commission. Liquidity The Company has incurred losses and significant deficiencies in cash flow from operations periodically over the past several years. As of March 31, 2002, the Company had a working capital deficit of $3,466,000. These factors among others may indicate that without increased cash flow from operations, sale of oil and gas properties or additional financing the Company may not be able to meet its obligations in a timely manner or be able to fund exploration and development of its oil and gas properties. During fiscal 2001 and 2000, the Company has raised approximately $3,902,000 and $2,402,000, respectively, through private placements and option exercises. In addition, the Company has sold properties to fund its working capital deficits and/or its funding needs. Recently, the Company has taken steps to generate cash flow from operations through the acquisition of producing oil and gas properties which management believes will generate sufficient cash flow to meet its obligations in a timely manner. Should the Company be unable to achieve its projected cash flow from operations additional financing or sale of oil and gas properties could be necessary. 7
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ----------------------------------------------------------------------------- (1) Liquidity, Continued The Company believes that it could sell oil and gas properties or obtain additional financing, although, there can be no assurance that such financing would be available on timely or acceptable terms. The Company had a contract to sell 6,000 barrels of oil a month at $22.31 through February 28, 2002 with Enron North America Corp., which we terminated on December 10, 2001. Delta has a claim in bankruptcy of approximately $185,000, but we do not expect to recover this claim. The impact of not recovering this claim is less than $.02 per share. Recently Issued Accounting Standards and Pronouncements SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact SFAS No. 143 will have on its financial condition and results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transaction. The Company is currently assessing the impact SFAS No. 144 will have on its financial condition and results of operations. (2) Investments The Company's investment in Bion Environmental Technologies, Inc. (Bion) is classified as an available for sale security and reported at its fair market value, with unrealized gains and losses excluded from earnings and reported as a separate component of stockholders' equity. 8
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ----------------------------------------------------------------------------- (2) Investments, Continued The cost and estimated market value of the Company's investment in Bion at March 31, 2002 and June 30, 2001 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value -------- ----------- --------- March 31, 2002 $152,000 (40,000) 112,000 ======== ======= ======= June 30, 2001 $152,000 69,000 221,000 ======== ======= ======= (3) Oil and Gas Properties On July 1, 2001, the Company purchased all the producing properties of Amber Resources Company, a 91.68% owned subsidiary of the Company, for $107,000. The purchase price was based on an evaluation performed by an unrelated engineering firm. The effects of this transaction are eliminated in these consolidated financial statements. On November 15, 2001, the Company acquired producing oil and gas interests in Texas from certain unrelated entities and an unrelated individual. The acquisition had a purchase price of approximately $788,000 consisting of $413,000 in cash and 137,000 shares of the Company's restricted common stock with a fair value of $375,000 based on the closing price on the date of closing. On February 19, 2002, Delta completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. Delta issued 1,374,240 shares of restricted common stock for 100% of the shares of Piper. The 1,374,240 shares of restricted common stock was valued at approximately $5,234,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, Delta issued 51,000 shares for the cancellation of certain debt of Piper. As a result of the acquisition, we acquired Piper's working and royalty interests in over 300 properties which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. This project is classified as held for sale at March 31, 2002 at its estimated fair value of $5,272,000. 9
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (3) Oil and Gas Properties, Continued On March 1, 2002, Delta completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2,750,000 pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. As a result of the sale, the Company recorded a loss of sale of oil and gas properties of $1,000. These properties accounted for approximately 9.45% of our total assets as of June 30, 2001 and also accounted for approximately 22.6% of our total revenues and approximately 11.9% of our total operating expenses during our past fiscal year. Approximately $1,300,000 of the proceeds from the sale were used to pay existing debt. On March 1, 2002, the Company sold the properties acquired on November 15, 2001, to Whiting Petroleum Corporation for $648,000. As a result of the Sale, the Company recorded a loss on sale of oil and gas properties of $106,000. Proceeds from the sale were used to pay existing debt. Unproved Undeveloped Offshore California Properties The Company has ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $9,722,000 and $9,359,000 March 31, 2002 and June 30, 2001, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company's investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off. See note 7 to the financial statements. On January 9, 2002, Delta and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of Delta's Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly 10
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (3) Oil and Gas Properties, Continued from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and Delta decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear Delta<s appeal of any such ruling or ultimately makes a determination adverse to Delta, it is likely that some or all of these leases would become impaired and written off at that time. In addition, it should be noted that Delta's pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with Delta is not settled, it would be necessary for Delta to reevaluate whether the leases should be considered impaired at that time. As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though Delta would undoubtedly proceed with its litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and Delta will continuously evaluate those factors as they occur. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Delta's claim (including the claim of its subsidiary Amber Resources Company) for lease bonuses and rentals paid by Delta and its predecessors is in excess of $152,000,000. In addition, its claim for exploration costs and related expenses will also be substantial. 11
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (3) Oil and Gas Properties, Continued Proposed Acquisition Delta entered into a Purchase and Sale Agreement to purchase all of the United States domestic oil and gas properties of Castle Energy Corporation ("Castle") for $20,000,000, payable in proceeds from bank financing in cash, plus 9,566,000 shares of Delta's Common Stock valued at approximately $37,977,000 based on the five-day average closing price surrounding the announcement of the acquisition. The effective date is October 1, 2001 and closing is expected to occur on May 31, 2002. Pursuant to the terms of the Purchase and Sale Agreement, the cash portion of the purchase price payable at closing will be reduced by the cash flow from the properties between the effective date and the closing date. The sale is subject to approval by the shareholders of Delta. Each party is subject to a penalty in the amount of 700,000 shares of their respective common stock for failure to close the transaction. Delta has an additional penalty in the amount of 700,000 shares of its Common Stock if the transaction is terminated by Castle because the closing does not occur by June 30, 2002 due to Delta's failure to timely respond to SEC comments, a determination by Delta not to proceed with the transaction or any other delay or failure to meet the conditions of closing, other than a failure to obtain shareholder approval in a situation where less than a majority of shares issued and outstanding can be voted, exclusive of broker non-votes, for, against or abstaining on the proposal to approve the agreement with Castle. Delta may repurchase up to 3,188,667 of its shares from Castle for $4.50 per share for a period of one year after closing. The option to repurchase up to 3,188,667 of our shares for $4.50 will preserve the potential upside relating to future value relating to our offshore oil and gas properties. If we decide to exercise our option to repurchase our shares, the value of the repurchased shares less the cost of the shares originally issued would be an adjustment to oil and gas properties. As a part of the acquisition, upon closing, Delta has granted an option to acquire a 4% working interest in the properties acquired for a cost of $974,000 to BWAB Limited Liability Company, a less than 10% shareholder of Delta. The difference between the $974,000 paid by BWAB, which is less than fair value, and 4% of the cost of the Castle properties will be treated as an additional acquisition cost by Delta for its consultation and assistance related to the transaction. Even though Delta has had conversations with a bank to provide the necessary financing at closing and has obtained a preliminary commitment letter from a bank for a loan to be collateralized by all unencumbered oil and gas properties in an amount of up to $20,000,000 with an interest rate of prime + 1-1/2% and a 3 year maturity date, the commitment is preliminary, may be withdrawn at any time and all of the stated terms are subject to change. 12
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (3) Oil and Gas Properties, Continued If the Company chooses to close the acquisition with a bridge note payable to Castle, there is no assurance that it could repay all or part of the bridge note with borrowed or other funds. If Delta is unable to pay all or a portion of the bridge note in cash, it may pay the unpaid portion in shares of Delta's Common Stock at $3.00 per share. However, in no event will Delta issue shares to Castle that would result in Castle holding more than 49.9% of Delta's outstanding Common Stock. In the event that Delta is unable to obtain sufficient cash to pay the bridge note when due, and the number of shares that would be issued to Castle to fully pay the bridge note would result in Castle holding more than 49.9% of the outstanding shares, Delta will only issue the maximum number of shares of Common Stock that is possible without causing Castle to own more than 49.9% of the outstanding shares. Any remaining amounts due shall continue to be due and payable in either cash or shares of Delta Common Stock as soon as it is possible for Delta to issue sufficient shares to pay the remaining amounts without causing Castle to own more than 49.9% of the outstanding shares. (4) Long Term Debt March 31, June 30, 2002 2001 ---------- ---------- A $6,371,000 $7,337,000 B 1,475,000 2,097,000 C 274,000 - ---------- ---------- $8,120,000 $9,434,000 Current Portion 3,186,000 3,038,000 ---------- ---------- Long-Term Portion $4,934,000 $6,396,000 ========== ========== 13
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (4) Long Term Debt, Continued A. On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from Kaiser-Francis Oil Company ("Lender"). In addition, the Company will be required to pay fees of $250,000 on June 1, 2002 and June 1, 2003 if the loan has not been retired prior to these dates. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and East Carlsbad field purchases. The Company is required to make minimum monthly payments of principal and interest equal to the greater of $150,000 or 75% of net cash flows from the acquisitions completed on November 1, 1999 and December 1, 1999. The loan is collateralized by the Company's oil and gas properties acquired with the loan proceeds. B. On October 25, 2000, the Company borrowed $3,000,000 at prime plus 3%, secured by the acquired interests in the Eland and Stadium fields in Stark County, North Dakota, from US Bank National Association (US Bank). The loan matures on August 31, 2003 and is collateralized by certain oil and gas properties. The Company is required to make monthly payments in the amount of 90% of the net revenue from the oil and gas properties collateralizing the loan. The Company is currently in compliance with the loan agreement. C. As a result of the merger with Piper on February 19, 2002, the Company established a note payable of $350,000 to John Wilson II, for amounts previously owed to him by Piper. The value of the note was $233,000 at March 31, 2002 and is due on May 19, 2002. The Company also assumed a note payable to Summit Bank which had a value of $40,000 at March 31, 2002 which was paid in full subsequent to March 31, 2002. (5) Stockholder's Equity On March 20, 2002 the Company issued 71,429 shares of its restricted common stock, at a price of $3.15 per share, to an unrelated individual for net proceeds of $225,000. An investment agreement with Swartz Private Equity, LLC ("Swartz") entitles the Company to issue and sell ("Put") up to $20 million of its common stock to Swartz, subject to a formula based on the Company's stock price and trading volume over a three year period following the effective date of a registration statement covering the resale of the shares to the public. Pursuant to the terms of this investment agreement the Company is not obligated to sell to Swartz all of the common stock referenced in the agreement nor does the Company intend to sell shares to the entity unless it is beneficial to the Company. 14
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (5) Stockholder's Equity, Continued To exercise a Put, the Company must have an effective registration statement on file with the Securities and Exchange Commission ("SEC") covering the resale to the public by Swartz of any shares that it acquires under the investment agreement. The Company has filed a registration statement covering the Swartz transaction with the SEC. Swartz will pay us the lesser of the market price for each share minus $0.25, or 91% of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date the Company exercises a Put is used to determine the purchase price Swartz will pay and the number of shares Delta will issue in return. If the Company does not Put at least $2,000,000 worth of common stock to Swartz during each one year period following shareholder approval of the Investment Agreement and registration with the SEC, the Company must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock the Company Puts to Swartz during the one-year period. The fee is due and payable on the last business day of each one-year period. Each annual non-usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. The Company is not required to pay the annual non-usage fee to Swartz in years it has met the Put requirements. The Company is also not required to deliver the non-usage fee payment until Swartz has paid the Company for all Puts that are due. If the investment agreement is terminated, the Company must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. The Company may terminate its right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of the Company's intention to terminate. However, any termination will not affect any other rights or obligations the Company has concerning the investment agreement or any related agreement. The Company cannot determine the exact number of shares of the Company's common stock issuable under the investment agreement and the resulting dilution to its existing shareholders, which will vary with the extent to which we utilize the investment agreement and the market price of our common stock. The investment agreement provides that the Company cannot issue shares of common stock that would exceed 20% of the outstanding stock on the date of a Put unless and until we obtain shareholder approval of the issuance of common stock. The Company will seek the required shareholder approval under the investment agreement and under NASDAQ rules. 15
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (6) Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share: Three Months Ended March 31, ------------------ 2002 2001 ---- ---- Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ (1,587,000) $ 331,000 ------------ ----------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 12,124,000 10,680,000 Effect of dilutive securities- stock options and warrants * 1,844,800 ------------ ----------- Denominator for diluted earnings per common share 12,124,000 12,524,000 ============ =========== Basic earnings per common share $ (.13) .03 ============ =========== Diluted earnings per common share (.13)* .03 ============ =========== *Potentially dilutive securities outstanding were anti-dilutive. 16
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (6) Earnings Per Share, Continued The following table sets forth the computation of basic and diluted earnings per share: Nine Months Ended March 31, ------------------ 2002 2001 ---- ---- Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ (3,493,000) $ 893,000 ------------ ----------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 11,513,000 10,049,000 Effect of dilutive securities- stock options and warrants * 1,736,000 ------------ ----------- Denominator for diluted earnings per common share 11,513,000 11,785,000 ============ =========== Basic earnings per common share $ (.30) .09 ============ =========== Diluted earnings per common share (.30)* .08 ============ =========== *Potentially dilutive securities outstanding were anti-dilutive. 17
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Nine Months Ended March 31, 2002 and 2001 (Unaudited) - ---------------------------------------------------------------------------- (7) Subsequent Events On May 7, 2002, the Company entered into an agreement with an unrelated individual to sell a building located in Ft. Worth, Texas which was acquired through the merger with Piper for approximately $430,000 net of commission. On May 8, 2002, the Company entered into an agreement with Tipperary Corporation ("Tipperary") to exchange our undivided interests in the Authorities to Prospect (ATP's) covering lands in Queensland, Australia acquired through the merger with Piper for certain interests in the West Buna Field, in Hardin and Jasper Counties, Texas, $700,000 in cash, 250,000 unregistered shares of Tipperary common stock and certain obligations owed by the Company not to exceed $600,000. The Company's basis in the ATP's is approximately $5,250,000. 18
Item 2. Management's Discussion and Analysis or Plan of Operations Forward Looking Statement ------------------------- The statements contained in this report which are not historical fact are "forward looking statements" that involve various important risks, uncertainties and other factors which could cause the Company's actual results to differ materially from those expressed in such forward looking statements. These factors include, without limitation, the risks and factors included in the following text as well as other risks previously discussed in the Company's annual report on Form 10-K/A. Liquidity and Capital Resources ------------------------------- General ------- At March 31, 2002, we had a working capital deficit of $3,466,000 compared to a working capital deficit of $1,560,000 at June 30, 2001. This increase in working capital deficit is primarily due to net losses incurred resulting from a decrease in oil and gas prices and the increase in accounts payable relating to additional drilling during the quarter. Offshore -------- Offshore Undeveloped Properties ------------------------------- The undeveloped leases in which we own interests were issued during the early 1980s (with the exception of the Sword Unit leases issued in 1979) and carried a primary term of five years. During those primary terms, oil and gas in commercial quantities were discovered in all of the unit areas in which we own interests. Applicable statutes and regulations require that a lease beyond its primary term must be maintained either by production or drilling operations (conducted under an approved Exploration Plan or Development and Production Plan, or under a suspension of production or suspension of operations). Applicable federal regulations set forth a number of reasons for which the MMS may either grant or direct a suspension of operations or suspension of production. It is common practice for lease suspensions of this nature to be issued by the MMS either to aid the operator in accommodating necessary activities or unavoidable delays or to accommodate environmental concerns or national security issues. These suspensions are issued when it is necessary to allow the proper development of unitized leases on which discoveries of commercial quantities of oil and gas have occurred. Our leases are currently held under suspensions issued on that basis. Although the issuance of future suspensions is subject to MMS discretion, the applicable statutes and regulations, as well as past practice in the Pacific Outer Continental Shelf region, support the issuance of future suspensions as necessary to facilitate development so long as the operators continue diligent efforts to achieve production. 19
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. There are certain milestones that were previously established by the MMS for four of our five undeveloped offshore California units ( with the exception of Rocky Point). The specific milestones for each of the four units vary depending upon the operator of the unit. On July 2, 2001, however, these milestones were suspended by the MMS in compliance with an order entered by a Federal Court on June 22, 2001 in the case of California v. Norton. In that case, the CCC sued the United States government claiming, in essence, that the lease suspensions that were granted by the MMS while the COOGER Study was being completed violated the requirements of the Coastal Zone Management Act because, in granting those suspensions, the MMS did not make a determination that the suspensions were consistent with California's coastal management program. The Court agreed with California and ordered the MMS to set aside its approval of the subject suspensions and to direct suspensions of all of the subject leases, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under the Coastal Zone Management Act. The July 2, 2001 letters from the MMS which direct suspension of the milestones indicate that the MMS will review the previously submitted (and approved) suspension requests under the provisions of the Coastal Zone Management Act as directed by the court. The current suspensions of operations directed by the letters do not specify an end date. The MMS has issued letters to all of the operators of the affected leases offering the opportunity to modify the previously submitted suspension of production requests. Burdette A. Ogle, a consultant to us for our offshore California properties, has informed us that he believes the end-date of the suspensions of production will likely be the anticipated spud date for the delineation wells set forth in the operators' respective requests for suspensions of production. During this period the leases will be held by the suspensions. The suspensions themselves authorize only preliminary activities, not operations, on the leases. The operations (i.e., drilling the next delineation wells) will be conducted under Exploration Plans ("EPs"). The operators intend to submit proposed Exploration Plans to the MMS for approval significantly before the expiration of the suspensions. Within 30 days of the date upon which the proposed EP is deemed "submitted" (usually after further revisions at the request of the MMS), the MMS is required to either: (1) approve the plan; (2) require the lessee to modify the plan, in which case the lessee may resubmit the modified plan; or (3) disapprove the plan if the MMS determines that the proposed activity would probably cause serious environmental harm which cannot be mitigated. Disapproval of an Exploration Plan does not, in and of itself, effect a cancellation of a lease. Under Federal Regulations (30 CFR Sec. 250.203(k)(2)), a lessee may resubmit a disapproved plan if there is a change in the circumstances which caused it to be disapproved. Further, the Federal Regulations contemplate that the lessee will work to modify the disapproved EP to accommodate the environmental concerns for a period of up to five years, during which time the lease would be held under a suspension. If the leases were ultimately cancelled on the basis of this Exploration Plan disapproval, the regulations contemplate that compensation would be required. 20
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. If an Exploration Plan were approved, a delineation well would be spudded prior to the end of the applicable suspension. Once drilling is underway, the lease is held by operations. At the end of drilling operations, the lessee has a 180-day period to commence further operations (under an Exploration Plan or a Development and Production Plan) or to obtain a further suspension. In practice, the lessee would seek a suspension to allow for time to evaluate the results of delineation drilling and prepare a Development and Production Plan. Again, the applicable sections of the regulations accommodate suspensions for this purpose. During any such suspension, the operator would submit a proposed Development and Production Plan to the MMS. Within 60 days of the last day of the applicable comment periods, the MMS must: (1) approve the Development and Production Plan; (2) require modification of the Development and Production Plan; or (3) disapprove the Development and Production Plan, due to (i) the operator's failure to comply with applicable law, (ii) failure to obtain state consistency concurrence, (iii) national security or defense issues, or (iv) environmental concerns. As with the Exploration Plan, disapproval does not effect a lease cancellation. Again, the regulations contemplate that the lessee will work to modify the disapproved Development and Production Plan (or resolve the Coastal Zone Management Act issues) for a period of up to five years, during which the lease would most likely be held under a granted suspension. All leases in which we hold an interest were originally issued for a primary term of five years. As discussed above, suspensions have the effect of extending the term of the lease for the period of the suspension. All of our leases must be maintained either through production, drilling operations or suspensions. Annual rentals under all leases equal $3/acre. Rentals were waived during the COOGER Study period (from January 1, 1993 through November 15, 1999). The MMS has also waived rentals during the current suspensions of operations beginning July 2, 2001. As these suspensions do not state a definite end date, the date through which rentals will be waived is not known. In January 2000, the two properties which are operated by Aera Energy, LLC, Lease OCS-P 0409 and the Point Sal Unit, had requirements to submit an interpretation of the merged 3-D survey of the Offshore Santa Maria Basin covering the properties. This milestone was accomplished in February 2000. The next milestone for these properties was to submit a Project Description for each property to the MMS in February 2000. The Project Description for each of the properties was submitted in February and after responding to an MMS request for additional information and clarification, revised Project Descriptions were submitted in September 2000. By letter dated July 21, 2000, Aera submitted a plan to the MMS for the voluntary re-unitization of the Offshore Santa Maria Basin, including the Lion Rock Unit and Lease OCS-P 0409, into one unit. This plan included a proposed time line for submitting the required unit agreement, initial plan of operations, and all geological, geophysical and engineering data supporting that request. Following that submission, MMS advised Aera that it now believes it would not support consolidating the Offshore Santa Maria Basin into one unit. 21
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Therefore, Aera is evaluating other unitization alternatives, which will then be reviewed with co-owners and the MMS. The previous suspensions of production on both the Lion Rock Unit and Lease OCS-P-0409 were scheduled to expire on November 1, 2002. Prior to the decision in the Norton case, the revised Exploration Plans and/or Development and Production Plans (DPP's) for the Aera properties were scheduled to be submitted to the MMS in September 2001. As the operator of the properties, Aera stated its intent to timely submit the EPs and DPPs. When the EPs and DPPs are submitted, it is currently estimated that it will cost $100,000, with Delta's share being $5,000. When and if milestones are reinstated by the MMS, it is anticipated that the next milestone for Aera would still be to show proof that a Request for Proposal (RFP) has been prepared and distributed to the appropriate drilling contractors as described in the revised Project Descriptions. At the time milestones were suspended by the MMS, the milestone date for the RFP was November 2001. The affected operating companies have formed a committee to cooperate in the process of mobilizing the mobile drilling unit. When necessary, it is anticipated that this committee will prepare the RFP for submission to the contractors and MMS. It is estimated that it will cost $210,000 to complete the RFPs, with Delta's share being $11,000. Unless delays are encountered as the result of the Norton case, drilling operations on the Point Sal Unit are still expected to begin in February 2003 with the drilling of a delineation well at an estimated cost of approximately $13,000,000. Delta's share is estimated at $650,000. No delineation well is necessary for Lease OSC-P 0409 as six wells have been drilled on the lease and a DPP was previously approved. The Sword and Gato Canyon Units are operated by Samedan Oil Corporation. In May 2000, Samedan acquired Conoco, Inc.'s interest in the Sword Unit. Prior to such time, as operator Conoco timely submitted the Project Description for the Sword Unit in February 2000. However, since becoming the operator, Samedan has informed the MMS that it has plans to submit a revised Project Description for the Sword Unit. The new plan is to develop the field from Platform Hermosa, an existing platform, rather than drilling a delineation well on Sword and then abandoning it. Prior to the suspension of milestones in accordance with the Court's order in the Norton case, the next scheduled milestone for the Sword Unit was the DPP for Platform Hermosa, which was to be submitted to the MMS in September 2001. When the DPP is filed, it is estimated that the cost will be approximately $360,000, with Delta's share being $11,000. In February 2000, Samedan timely submitted the Project Description for the Gato Canyon Unit. In August 2000, after responding to an MMS request for additional information and clarification, Samedan filed the revised Project Description. Prior to the suspensions granted under the Norton decision, the updated Exploration Plan for the Gato Canyon Unit was to be submitted to the MMS in September 2001. It is estimated that the cost of the updated Exploration Plan will be approximately $300,000, with Delta's share being $50,000. If and when milestones are reinstated, it is anticipated that the next milestone for Gato Canyon would still be to show proof that a Request for Proposal has been prepared and distributed to the appropriate drilling contractors as described in the revised Project Descriptions. At the time milestones were suspended by the MMS, the milestone date for the RFP was 22
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. November 2001. It is anticipated that the same committee that is preparing the RFPs for the Aera properties will prepare the RFP for Gato Canyon for submittal to the contractors and MMS. It is estimated that it will cost $450,000 to complete the RFP, with Delta's cost estimated at $75,000. Prior to its suspension, the last milestone was to begin drilling operations on the Gato Canyon Unit by May 1, 2003 using the committee's mobile drilling unit. The cost of the drilling operations is estimated to be $11,000,000, with Delta's share being $1,750,000. As a result of the Norton case, the Rocky Point Unit leases are held under directed suspensions of operations with no specified end date. The United States government appealed the court's order in the Norton case. The Unit operator timely submitted a Project Description for the development program to the MMS as the first milestone in the Schedule of Activities for the Unit. The operator, under the auspices of the MMS, has also made a presentation of the Project to the affected Federal, state and local agencies. It is anticipated that the Rocky Point Unit will be developed from existing facilities within the Point Arguello Field, which is currently in production under previously approved Development and Production Plans. The existing Point Arguello Unit DPPs were found to be consistent with California's Coastal Zone Management Plan when originally approved. As the development of the Rocky Point Unit will require only revision of the existing Point Arguello Field DPPs, it is only the proposed revision to the existing DPPs that must now be found to be consistent with the Coastal Zone Management Plan. The operator has determined that the proposed Rocky Point Unit development activities comply with the State of California's approved coastal management program and will be conducted in a manner consistent with such program. That conclusion is based on an extensive environmental evaluation set forth in supporting information submitted to the MMS with the proposed revisions to Point Arguello Field DPPs and the evaluation may be accessed on the internet at http://www.mms.gov/omm/pacific/lease/rpu-pdfs/RPU-Supporting- Information.pdf. By correspondence dated August 7, 2001, however, the unit operator requested that the CCC suspend the consistency review for a revised Development and Porduction Plan since the MMS had temporarily stopped work on processing of the plan as the result of the Norton decision. Our working interest share of the future estimated development costs based on estimates developed by the operating partners relating to four of our five undeveloped offshore California units is approximately $210 million. No significant amounts are expected to be incurred during fiscal 2002, and $1.0 million and $4.2 million are expected to be incurred during fiscal 2003 and 2004, respectively. Because the amounts required for development of these undeveloped properties are so substantial relative to our present financial resources, we may ultimately determine to farmout all or a portion of our interests. If we were to farmout our interests, our interest in the properties would be decreased substantially. In the event that we are not able to pay our share of expenses as a working interest owner as required by the respective operating agreements, it is possible that we might lose some portion of our ownership interest in the properties under some circumstances, or that we might be subject to penalties which would result in the forfeiture 23
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. of substantial revenues from the properties. Alternatively, we may pursue other methods of financing, including selling equity or debt securities. There can be no assurance that we can obtain any such financing. If we were to sell additional equity securities to finance the development of the properties, the existing common shareholders' interest would be diluted significantly. There are additional, as yet undetermined, costs that we expect in connection with the development of the fifth undeveloped property in which we have an interest (Rocky Point Unit). At the present time we believe that all of the costs capitalized for our offshore California properties will be fully recovered through future development and production in spite of the factors discussed above, including, without limitation, the delays that have been encountered in preparing the Development and Production Plan for the Rocky Point Unit, the current uncertainty as to whether that plan will be found to be consistent with the California Coastal Zone Management Plan, our inability to submit exploration plans for the Point Sal, Lion Rock, Gato Canyon and Sword Units since their acquisition in 1992, the extensive development necessary to access reserves on those Units, the uncertainty created by the court ruling in June, 2001 in the Norton case, the current suspension of operations prohibiting exploratory activities on the properties and our inability to effect any development due to our status as an investor as opposed to being the operator of the properties. Based on discussions with the MMS and operators of the properties, we currently believe that the MMS, in cooperation with the property interest owners, will provide the State of California with a consistency determination under the Coastal Zone Management Act that will allow exploration and development plans to be prepared. Furthermore, we believe that the MMS will seek to modify the previously submitted suspension of production requests to focus solely on "preliminary activities," and will approve new suspensions of production requests that do not contain any "milestones" per se, as the stated milestones in the previous suspensions of production appear to have been a significant factor in the court's decisions. We also believe that the end-date of any such new suspensions of production will likely be the anticipated spud date for the delineation wells set forth in the operators' respective requests for suspensions of production. Even though we are not the designated operator of the properties and regulatory approvals have not been obtained, we believe exploration and development activities on these properties will occur and we are committed to expend funds attributable to our interests in order to proceed with obtaining the approvals for the exploration and development activities. We have also commenced litigation against the U.S. Government seeking damages in the event that we are not allowed to proceed. Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair value of our property interests are in excess of their carrying value at December 31, 2001 and June 30, 2001 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off. See note 3 to the financial statements. 24
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Offshore Producing Properties ----------------------------- Point Arguello Unit. Pursuant to a financial arrangement between Whiting and us, we hold what is essentially the economic equivalent of a 6.07% working interest, which we call a "net operating interest," in the Point Arguello Unit and related facilities. In layman's terms, the term "net operating interest" is defined in our agreement with Whiting as being the positive or negative cash flow resulting to the interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and ad valorem taxes, capital expenditures, Unit fees and certain other expenses from the oil and gas sales and certain other revenues that are attributable to the interest. Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa), which are operated by Arguello, Inc., a subsidiary of Plains Resources, Inc. In an agreement between Whiting and Delta (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities. There continues to be on going drilling and workover activity and we anticipate that we will participate in the drilling of at least four new wells in fiscal 2002. Each well will cost approximately $2.8 million ($170,000 to our interest). We anticipate the drilling costs to be paid through current operations or additional financing. Onshore Producing Properties ---------------------------- We estimate our capital expenditures for onshore properties to be approximately $1.1 million for the year ended June 30, 2002. However, we are not obligated to participate in future drilling programs and will not enter into future commitments to do so unless management believes we have the ability to fund such projects. Equity Transactions ------------------- Agreement with Swartz --------------------- See Note (5) to Consolidated Financial Statements Options ------- We received the proceeds from the exercise of options to purchase shares of our common stock of $399,000 during the nine months ended March 31, 2002 and $1,480,000 during the year ended June 30, 2001. 25
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Capital Resources ----------------- We expect to raise additional capital by selling our common stock in order to fund our capital requirements for our portion of the costs of the drilling and completion of development wells on our proved undeveloped properties during the next twelve months. There is no assurance that we will be able to do so or that we will be able to do so upon terms that are acceptable. We will continue to explore additional sources of both short-term and long-term liquidity to fund our operations and our capital requirements for development of our properties including establishing a credit facility, sale of equity or debt securities and sale of properties. Many of the factors, which may affect our future operating performance and liquidity are beyond our control, including oil and natural gas prices and the availability of financing. After evaluation of the considerations described above, we presently believe that our cash flow from our existing producing properties and other sources of funds will be adequate to fund our operating expenses and satisfy our other current liabilities over the next year or longer. If it were necessary to sell an existing producing property or properties to meet our operating expenses and satisfy our other current liabilities over the next year or longer we believe we would have the ability to do so. On February 1, 2002, we sold interests in 20 producing wells, 5 injection wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota for $2,750,000 to Sovereign Holdings, LLC, an unrelated entity. As a result of the sale, the Company recognized at December 31, 2001 an impairment of $102,000. Results of Operations --------------------- Income (loss). We reported a net loss for the three and nine months ended March 31, 2002 of $1,587,000 and $3,493,000 compared to net income of $331,000 and $893,000 for the three and nine months ended March 31, 2001. The net loss and net income for the three and nine months ended March 31, 2002 and 2001 were affected by numerous items, described in detail below. Revenue. Total revenues for the three and nine months ended March 31, 2002 were $1,058,000 and $5,290,000 compared to $3,702,000 and $9,509,000 for the three and nine months ended March 31, 2001. Oil and gas sales for the three and nine months ended March 31, 2002 were $1,138,000 and $5,317,000 compared to $3,661,000 and $9,352,000 for the three and nine months ended March 31, 2001. The decrease in oil and gas revenue is primarily attributed to the decrease in oil and gas prices and the sale of the Eland properties offset by additional production relating to certain acquisitions during fiscal 2001. 26
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Production volumes and average prices received for the three months ended December 31, 2001 and 2000 are as follows: Three Months Ended March 31, 2002 2001 Onshore Offshore Onshore Offshore Production: Oil (barrels) 5,180 62,496 26,946 84,566 Gas (Mcf) 153,979 - 157,863 - Average Price: Net of forward contract sales Oil (per barrel) $17.26 $13.24 $29.04 $19.70 Gas (per Mcf) $ 1.43 - $ 7.62 - Gross of forward contract sales* Oil (per barrel) $17.26 $13.24 $29.04 $19.70 Gas (per Mcf) $ 1.43 - $ 7.62 - Production volumes and average prices received for the nine months ended March 31, 2002 and 2001 are as follows: Nine Months Ended March 31, 2002 2001 Onshore Offshore Onshore Offshore Production: Oil (barrels) 61,101 206,734 81,530 245,495 Gas (Mcf) 471,299 - 393,968 - Average Price: Net of forward contract sales Oil (per barrel) $21.70 $13.81 $28.30 $18.17 Gas (per Mcf) $ 2.41 - $ 6.54 - Gross of forward contract sales* Oil (per barrel) $21.84 $13.81 $28.30 $23.23 Gas (per Mcf) $ 2.41 - $ 6.54 - *We sold 25,000 barrels of our offshore production per month from June 2000 to December 2000 at $14.65 per barrel under fixed price contracts with production purchases. We received the benefit of 6,000 barrels per month from March 1, 2001 through October 31, 2001 at $27.31 per barrel under fixed price contracts with Enron North American Corp ("Enron"). After Enron filed bankruptcy, we terminated our fixed price contract. We expect to have a claim in bankruptcy, but do not expect to recover these claims. Other Revenue. Other revenue in fiscal 2001 includes amounts recognized from production of gas previously deferred pending determination of our interests in the properties. 27
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Lease Operating Expenses. Lease operating expenses were $865,000 and $2,679,000 for the three and nine months ended March 31, 2002 compared to $1,520,000 and $3,783,000 for the same period in 2001. On a barrel equivalent basis, lease operating expenses were $4.06 and $4.12 for the three and nine months ended March 31, 2002 compared to $3.23 and $4.37 for the same periods in 2001 for onshore properties. On a barrel equivalent basis, lease operating expenses were $11.82 and $10.17 for the three and nine months ended March 31, 2002 compared to $15.89 and $12.72 for the same periods in 2001 for the offshore properties. The decrease in lease operating expense is attributed to lower offshore operating cost after the completion of an extensive workover program during fiscal 2001 and the sale of the Eland properties. Depreciation and Depletion Expense. Depreciation and depletion expense for the three and nine months ended March 31, 2002 was $587,000 and $2,249,000 compared to $600,000 and $1,556,000 for the same period in 2001. On a barrel equivalent basis, the depletion rates were $9.34 and $10.08 for the three and nine months ended March 31, 2002 and $7.80 and $6.49 for the same periods in 2001 for onshore properties. On a barrel equivalent basis, the depletion rates were $4.05 and $4.77 for the three and nine months ended March 31, 2002 compared to $2.44 and $2.17 for the same periods in 2001 for offshore properties. The decrease in depletion expense is attributed to the sale of the Eland properties. Exploration Expenses. We incurred exploration expenses of $16,000 and $125,000 for the three and nine months ended March 31, 2002 compared to $26,000 and $49,000 for the same period in 2001. Exploration expense increased from last year as the Company expanded its activity in South Dakota and offshore California. Dry Hole Cost. We incurred dry hole cost of $15,000 and $396,000 for the three and nine months ended March 31, 2002 relating to five dry holes. Abandoned and Impaired Properties. We impaired $60,000 relating to undeveloped properties in onshore California and $102,000 relating to our Eland and Stadium fields in Stark County, North Dakota, which were sold on February 1, 2002 during the quarter ended December 31, 2001. Professional fees Professional fees for the three and nine months ended March 31, 2002 were $284,000 and $954,000 compared to $348,000 and $815,000 for the same period in 2001. The increase during the nine months in professional fees was primarily attributed legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to the company's undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for the three and nine months ended March 31, 2002 were $593,000 and $954,000 compared to $268,000 and $896,000 for the same periods in 2001. The increase in general and administrative expenses was attributable to the hiring of additional employees, moving expenses and bonuses. Stock Option Expense. Stock option expense has been recorded for the three and nine months ended March 31, 2002 of $20,000 and $53,000 compared to $45,000 and $334,000 for the same period in 2001, for options granted to for non-employee directors at option prices below the market price at the date of grant. 28
Item 2. Management's Discussion and Analysis or Plan of Operations, Cont'd. Other income. Other income during the nine months ended March 31, 2001 includes the sale of our unsecured claim in bankruptcy against our former parent, Underwriters Financial Group in the amount of $350,000. Interest and Financing Costs. Interest and financing costs for the three and nine months ended March 31, 2002 were $274,000 and $947,000 compared to $504,000 and $1,495,000 for the same period in 2001. The decrease in interest expense can be attributed to lower interest rates established through traditional financing and the reduction of debt from the proceeds from the sale of the Eland properties. Item 3. Market Risk Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars. We did have a contract to sell 6,000 barrels a month at $27.31 through February 28, 2002 with Enron North American Corp, which we canceled on December 10, 2001 based on the uncertainty of Enron's future. We were subject to interest rate risk on $8,120,000 of variable rate debt obligations at March 31, 2002. The annual effect of a one percent change in interest rates would be approximately $81,000. The interest rate on these variable rate debt obligations approximates current market rates as of March 31, 2002. 29
PART II - OTHER INFORMATION Item 1. Legal Proceedings. On January 9, 2002, we filed a lawsuit along with several other companies 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 our Offshore California properties. The Complaint is based on our collective claims that post-leasing amendments to a federal statute governing offshore activities have now been interpreted to alter significantly our rights and abilities to move forward with further exploration and development activities, and that the Government has failed to carry out its own obligations under the leases which has resulted in substantial delays and interference in our exploration and development efforts. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs, and related expenses. The total amount claimed by all of the collective plaintiffs for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Our claim (including the claim of our subsidiary Amber Resources Company) for lease bonuses and rentals paid by us and our predecessors is in excess of $152,000,000. In addition, we have asserted a claim for exploration costs and related expenses. The U.S. Government has not yet filed an answer to our Complaint. Item 2. Changes in Securities. During the quarter ended March 31, 2002, Delta issued securities in transactions that were not registered under the Securities Act of 1933 as follows: On February 19, 2002, Delta completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. Delta issued 1,374,240 shares of restricted common stock for 100% of the shares of Piper to the shareholders of Piper. The 1,374,240 shares of restricted common stock was valued at approximately $5,244,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, Delta issued 51,000 shares to one person for the cancellation of certain debt of Piper. As a result of the acquisition, we acquired Piper's working and royalty interests in over 300 properties which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. In connection with this transaction, Delta relied on Section 4(2) of the Securities Act of 1933, as amended, and Rule 506 adopted thereunder. On March 20, 2002 the Company issued 71,429 shares of its restricted common stock, at a price of $3.15 per share, to an unrelated individual for net proceeds of $225,000. In connection with this transaction we relied on the exemption from registration provided by Section 4(2) of the Securities Act. 30
Item 3. Defaults Upon Senior Securities. None. Item 4. Submission of Matters to a Vote of Security Holders. None Item 5. Other Information. None Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. None. (b) Reports on Form 8-K. During the quarter ended March 31, 2002, Delta filed Reports on Form 8-K as follows: 1. Report on Form 8-K dated January 15, 2002, reporting information under Items 5 and 7. 2. Report on Form 8-K dated March 1, 2002, reporting information under Items 2, 5 and 7 of that form, including pro forma financial statements. 31
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amended Report to be signed on its behalf by the undersigned, thereunto duly authorized. DELTA PETROLEUM CORPORATION (Registrant) By: /s/ Roger A. Parker ----------------------------- Roger A. Parker President and Chief Executive Officer By: /s/ Kevin K. Nanke ----------------------------- Kevin K. Nanke, Treasurer and Chief Financial Officer Date: May 14, 2002 32