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 September 30, 2003 [ ] 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___ 24,547,000 shares of common stock $.01 par value were outstanding as of October 31, 2003.
FORM 10-Q 1st QTR. FY 2004 INDEX PART I FINANCIAL INFORMATION PAGE NO. Item 1. Consolidated Financial Statements Consolidated Balance Sheets - September 30, 2003 and June 30, 2003 (unaudited).................................... 1 Consolidated Statements of Operations - Three Months Ended September 30, 2003 and 2002 (unaudited)...................... 2 Consolidated Statement of Stockholders' Equity and Comprehensive Income (loss) Year Ended June 30, 2003 and Three Months Ended September 30, 2003 (unaudited)............ 3 Consolidated Statements of Cash Flows - Three Months Ended September 30, 2003 and 2002 (unaudited)...................... 4 Notes to Consolidated Financial Statements (unaudited)....... 5 Item 2. Management's Discussion and Analysis or Plan of Operations........................................ 14 Item 3. Quantitative and Qualitative Disclosures About Market Risk... 21 Item 4. Controls and Procedures...................................... 22 PART II OTHER INFORMATION Item 1. Legal Proceedings............................................ 22 Item 2. Changes in Securities........................................ 23 Item 3. Defaults upon Senior Securities.............................. 23 Item 4. Submission of Matters to a Vote of Security Holders............................................. 23 Item 5. Other Information............................................ 23 Item 6. Exhibits and Reports on Form 8-K............................. 23 The terms "Delta," "Company," "we," "our," and "us" refer to Delta Petroleum Corporation unless the context suggests otherwise. i
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - ----------------------------------------------------------------------------- <TABLE> <CAPTION> September 30, June 30, 2003 2003 ------------ ------------ (Unaudited) <S> <C> <C> ASSETS Current Assets: Cash and cash equivalents $ 1,498,000 $ 2,271,000 Marketable securities available for sale 538,000 662,000 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 at September 30, 2003 and June 30, 2003 4,135,000 4,410,000 Prepaid assets 829,000 764,000 Other current assets 456,000 560,000 ------------ ------------ Total current assets 7,456,000 8,667,000 ------------ ------------ Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting) 107,543,000 90,487,000 Less accumulated depreciation and depletion (14,345,000) (12,669,000) ------------ ------------ Net property and equipment 93,198,000 77,818,000 ------------ ------------ Long term assets: Deferred financing costs 84,000 117,000 Partnership net assets 111,000 245,000 ------------ ------------ Total long term assets 195,000 362,000 $100,849,000 $ 86,847,000 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current portion of long-term debt $ 11,199,000 $ 10,039,000 Accounts payable 5,543,000 3,604,000 Derivative instruments - 468,000 Current foreign tax payable 703,000 703,000 Other accrued liabilities 584,000 1,087,000 ------------ ------------ Total current liabilities 18,029,000 15,901,000 ------------ ------------ Long-term Liabilities: Asset retirement obligation 1,047,000 868,000 Long-term debt, net 26,508,000 22,175,000 ------------ ------------ Total long-term liabilities 27,555,000 23,043,000 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 23,418,000 shares at September 30, 2003 and 23,286,000 at June 30, 2003 244,000 233,000 Additional paid-in capital 81,277,000 75,642,000 Accumulated other comprehensive loss (24,000) (376,000) Accumulated deficit (26,232,000) (27,596,000) ------------ ------------ Total stockholders' equity 55,265,000 47,903,000 ------------ ------------ Commitments $100,849,000 $86,847,000 ============ ============ </TABLE> See accompanying notes to consolidated financial statements. 1 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS - ----------------------------------------------------------------------------- <TABLE> <CAPTION> Three Months Ended September 30, September 30, 2003 2002 ------------- ------------- <S> <C> <C> Revenue: Oil and gas sales $7,756,000 $5,467,000 Realized loss on derivative instruments, net (312,000) (33,000) ---------- ---------- Total revenue 7,444,000 5,434,000 Operating expenses: Lease operating expense 2,326,000 2,069,000 Depreciation and depletion 1,692,000 1,685,000 Exploration expense 130,000 7,000 Professional fees 304,000 177,000 General and administrative (includes stock option expense of $105,000 and $11,000 for the three months ended September 30, 2003 and 2002, respectively.) 1,139,000 862,000 ---------- ---------- Total operating expenses 5,591,000 4,800,000 ---------- ---------- Income from operations 1,853,000 634,000 Other income and (expense): Other income 20,000 11,000 Interest and financing costs (509,000) (508,000) ---------- ---------- Total other expense (489,000) (497,000) ---------- ---------- Income before cumulative effect of change in accounting principle 1,364,000 137,000 Cumulative effect of change in accounting principle - (20,000) ---------- ---------- Net income $1,364,000 $ 117,000 ========== ========== Net income per common share: Basic $ 0.06 $0.01 ========== ========== Diluted $ 0.05 * ========== ========== * less than $.01 per share </TABLE> See accompanying notes to consolidated financial statements. 2
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss) Year ended June 30, 2003 and Three Months Ended September 30, 2003 - ----------------------------------------------------------------------------- <TABLE> <CAPTION> Accumu- lated other compre- Additional Put Option hensive Common Stock paid-in on income Comprehensive Accumulated Shares Amount capital Delta stock (loss) income (loss) deficit Total ---------- -------- ----------- ------------ --------- -------------- ----------- ---------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Balance, July 1, 2002 22,618,000 $226,000 76,514,000 (2,886,000) (85,000) (28,853,000) 44,916,000 Comprehensive loss: Net income - - - - - 1,257,000 1,257,000 1,257,000 ----------- Other comprehensive loss, net of tax Change in fair value of derivative hedging instruments - - - - (468,000) (468,000) - (468,000) Unrealized gain on equity securities, net - - - - 177,000 177,000 - 177,000 ---------- Comprehensive income - - - - - 966,000 - ========== Stock options granted as compensation - - 124,000 - - - 124,000 Put option on Delta stock - - (2,886,000) 2,886,000 - Shares issued for oil and gas properties 200,000 2,000 920,000 - - - 922,000 Shares issued for cash upon exercise of options 468,000 5,000 970,000 - - - 975,000 ---------- -------- ----------- ----------- ---------- ----------- ----------- Balance, June 30, 2003 23,286,000 233,000 75,642,000 - (376,000) (27,596,000) 47,903,000 Comprehensive loss: Net income - - - - - 1,364,000 1,364,000 1,364,000 ---------- Other comprehensive loss, net of tax Change in fair value of derivative hedging instruments - - - - 476,000 476,000 - 476,000 Unrealized gain on equity securities, net - - - - (124,000) (124,000) - (124,000) ---------- Comprehensive income - - - - - 1,716,000 ========== Stock options granted as compensation - - 105,000 - - - 105,000 Shares issued for oil and gas properties 1,000,000 10,000 5,140,000 - - - 5,150,000 Shares issued for cash upon exercise of options 132,000 1,000 390,000 - - - 391,000 ---------- -------- ----------- ----------- --------- ------------ ----------- Balance, September 30, 2003 24,418,000 $244,000 81,277,000 - (24,000) (26,232,000) 55,265,000 ========== ======== =========== =========== ========= ============ =========== </TABLE> See accompanying notes to consolidated financial statements. 3
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - ----------------------------------------------------------------------------- <TABLE> <CAPTION> Three Months Ended September 30, September 30, 2003 2002 ------------- ------------- <S> <C> <C> Cash flows operating activities: Net income $ 1,364,000 $ 117,000 Adjustments to reconcile net income to cash provided by operating activities: Depreciation and depletion 1,692,000 1,685,000 Stock option expense 105,000 11,000 Amortization of financing costs 127,000 101,000 Cumulative effect on change in accounting principle - 20,000 Net changes in operating assets and operating liabilities: Decrease in trade accounts receivable 275,000 1,083,000 Increase in prepaid assets (65,000) (208,000) Decrease in other current assets 18,000 4,000 Increase (decrease) in accounts payable trade 1,939,000 (74,000) Increase (decrease) in other accrued liabilities (503,000) 416,000 ----------- ----------- Net cash provided by operating activities $ 4,952,000 $ 3,155,000 ----------- ----------- Cash flows from investing activities: Additions to property and equipment, net (5,743,000) (1,139,000) Decrease in long term assets 134,000 169,000 ----------- ----------- Net cash used in investing activities (5,609,000) (970,000) ----------- ----------- Cash flows from financing activities: Stock issued for cash upon exercise of options 391,000 40,000 Proceeds from borrowings 1,080,000 - Repayment of borrowings (1,587,000) (355,000) ----------- ----------- Net cash used in financing activities (116,000) (315,000) ----------- ----------- Net increase (decrease) in cash and cash equivalents (773,000) 1,870,000 ----------- ----------- Cash at beginning of period 2,271,000 1,024,000 ----------- ----------- Cash at end of period $ 1,498,000 $ 2,894,000 =========== =========== Supplemental cash flow information - Cash paid for interest and financing costs $ 460,000 $ 310,000 =========== =========== Non-cash financing activities: Common stock issued for the purchase of oil and gas properties $ 5,150,000 $ - =========== =========== </TABLE> See accompanying notes to consolidated financial statements. 4
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 (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. 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 for the year ended June 30, 2003, previously filed with the Securities and Exchange Commission. 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, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation. Actual results could differ from these estimates. 5
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 (Unaudited) - ----------------------------------------------------------------------------- (2) Recently Issued or Proposed Accounting Standards and Pronouncements We have been made aware that an issue has arisen within the industry regarding the application of provisions of SFAS No. 142 and SFAS No. 141, "Business Combinations," to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires companies to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, we and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. Also under consideration is whether SFAS No. 142 requires registrants to provide the additional disclosures prescribed by SFAS No. 142 for intangible assets for costs associated with mineral rights. If it is ultimately determined that SFAS No. 142 requires us to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts that would be reclassified are as follows: September 30, June, 2003 2003 ----------- ----------- INTANGIBLE ASSETS: Proved leasehold acquisition costs $75,450,000 $68,966,000 Unproved leasehold acquisition costs 17,349,000 10,164,000 ----------- ----------- Total leasehold acquisition costs 92,799,000 79,130,000 Less: Accumulated depletion 10,383,000 9,028,000 ----------- ----------- Net leasehold acquisition costs $82,416,000 $70,102,000 =========== =========== The reclassification of these amounts would not affect the method in which such costs are amortized or the manner in which we assess impairment of capitalized costs. As a result, net income would not be affected by the reclassification. 6
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 (Unaudited) - ----------------------------------------------------------------------------- (3) Marketable Securities The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards No. 115 (SFAS 115), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings. <TABLE> <CAPTION> Cumulative Unrealized Estimated Cost Gain (loss) Market Value -------- ----------- ------------ <S> <C> <C> <C> September 30, 2003 Bion Environmental Technologies, Inc. $152,000 $(139,000) $ 13,000 Tipperary Oil & Gas Company $418,000 $ 107,000 $525,000 -------- --------- -------- $570,000 $ (32,000) $538,000 ======== ========= ======== Cumulative Unrealized Estimated Cost Gain (loss) Market Value -------- ----------- ------------ June 30, 2003 Bion Environmental Technologies, Inc. $152,000 $(140,000) $ 12,000 Tipperary Oil & Gas Company $418,000 $ 232,000 $650,000 -------- --------- -------- $570,000 $ 92,000 $662,000 ======== ========= ======== </TABLE> (4) Oil and Gas Properties 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 $10,198,000, at September 30, 2003. 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. 7
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 (Unaudited) - ----------------------------------------------------------------------------- (4) Oil and Gas Properties, Continued Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at September 30, 2003 and that no impairment in the carrying values has occurred. Pursuant to a ruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. Government is required to make a consistency determination relating to our 1999 lease suspension requests under a 1990 amendment to the Coastal Zone Management Act. In the event that there is some future adverse ruling under the Coastal Zone Management Act that we decide not to appeal or that we appeal without success, it is likely that some or all of our interests in these leases would become impaired and written off at that time. It is also possible that other events could occur during the Coastal Zone Management Act review or appellate process that would cause our interests in the leases to become impaired, and we will continuously evaluate those factors as they occur. On January 9, 2002, the Company 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 our Offshore California properties. See disclosure in Item 1 of Part II. Fiscal 2004 - Acquisition On September 19, 2003, the Company completed an acquisition of certain production and drilling prospects in Colorado and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, "Davis"), pursuant to the terms of a Purchase and Sale Agreement effective as of August 1, 2003. The total consideration paid for these properties was 1,000,000 shares of our common stock and $8 million, of which $2 million was paid in cash and $6 million in the form of a short-term promissory note payable which was paid on October 3, 2003. The shares issued were recorded at a price of $5.15, a five day average surrounding the announcement of the transaction. The Company recorded an upward purchase price adjustment of approximately $318,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of August 1, 2003 through the closing date of September 19, 2003. The total acquisition cost of $13,468,000 was allocated between proved developed producing of $6,318,000 and unproved undeveloped of $7,150,000 based on preliminary information. The Company will also be obligated to issue additional shares of common stock to Davis in the event that it is determined that valid drillable prospects for the discovery and production of hydrocarbons on certain leases, or land pooled therewith, meet certain requirements, including a determination that there are at least 1,000,000 barrels of recoverable oil or six billion cubic feet of recoverable gas, or a combination thereof, in an individual prospect. These prospects are referred to as "Bonus Prospects." Davis will receive up to 190,000 (not more that $950,000 worth of stock) shares for each Bonus Prospect. No more than 1,900,000 shares will be issued to Davis under this provision, regardless of how many barrels of oil equivalent may be found. Davis also has the option to elect to take assignment of up to a 50% working interest in each well drilled on a Bonus Prospect after payout, on a well-by- well basis. 8
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 (Unaudited) - ----------------------------------------------------------------------------- (5) Long Term Debt September 30, 2003 June 30, 2003 A $27,548,000 $27,668,000 B $ 4,159,000 $ 4,546,000 C $ 6,000,000 $ - ----------- ----------- $37,707,000 $32,214,000 Current Portion $11,199,000 $10,039,000 ----------- ----------- Long-Term Portion $26,508,000 $22,175,000 =========== =========== A On June 20, 2003, the Company increased its credit facility from $20 million to $29.3 million with Bank of Oklahoma and Local Oklahoma Bank (the "Banks"). The facility has a variable interest rate component of prime + 1.5%/-.5% based on the total debt outstanding and a monthly commitment reduction of $600,000. The Company paid a 1% commitment fee in aggregate to the Banks. This fee was recorded as a deferred financing fee and will be amortized over the life of the loan which matures on May 31, 2005 and is collateralized by substantially all of Delta's oil and gas properties excluding the oil and gas properties collateralized under the Kaiser-Francis Oil Company ("KFOC") note discussed below. The Company's borrowing base and monthly commitment amount will be redetermined at least semi-annually. If as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt ever exceeds the amount of the revolving commitment then in effect, then within 30 days after we are notified by the Bank of Oklahoma, we must make a mandatory prepayment of principal that is sufficient to cause our total outstanding indebtedness to not exceed our borrowing base. The Company is required to meet quarterly debt covenants and restrictions. At September 30, 2003, the Company was in compliance with its quarterly debt covenants and restrictions. On October 1, 2003, the Company increased its credit facility to $34.0 million and on October 3, 2003, the Company increased its borrowings under the facility to the full $34.0 million and paid off the Davis note discussed in C. below. Beginning November 1, 2003, the Company=s monthly commitment reduction will increase to $640,000. 9
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 - ----------------------------------------------------------------------------- (5) Long Term Debt, Continued B On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from KFOC. In addition, the Company will be required to pay a fee of $250,000 on June 1, 2004 if the loan has not been retired prior to this date. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and New Mexico acquisitions. 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 remaining oil and gas properties acquired with the loan proceeds. C On September 19, 2003, the Company borrowed $6,000,000 at prime plus 2% from Davis in connection with the acquisition discussed earlier. The note was paid on October 3, 2003 as required. Maturities of long-term debt for each of the five years following September 30, 2003 are as follows: YEAR ENDING September 30, 2004................................ $11,199,000 2005................................ 7,680,000 2006................................ 7,680,000 2007................................ 7,680,000 2008................................ 3,468,000 ----------- $37,707,000 =========== (6) Stockholders' Equity Stock Option Plans The Company accounts for its stock option plans in accordance with the provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. In December, 2002 the FASB issued SFAS No. 148, "Accounting for Stock-based Compensation-Transition and Disclosure." SFAS 148 amends FASB Statement No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 have no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common stock. 10
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 - ----------------------------------------------------------------------------- (6) Stockholders' Equity, Continued Had compensation cost for the Company's stock-based compensation plan been determined using the fair value of the options at the grant date, the Company's net loss for the three months ended September 30, 2003 and 2002 would have been as follows: September 30, ------------------------------- 2003 2002 ---- ---- Net Income $ 1,364,000 $ 117,000 FAS 123 compensation effect (4,316,000)* (173,000) ----------- ---------- Net loss after FAS 123 compensation effect $(2,952,000) $ (56,000) =========== ========== Loss per common share: $ (.13) $ ** =========== ========== *During the quarter ended September 30, 2003 the Company granted to its officers options to purchase 1,250,000 shares of its common stock at a price of $5.29 per share, which was the market price on the date of the grant. All of these options vested immediately upon issuance. The fair market value of each option granted was $3.45 and was calculated using a risk free rate of 4.34%, volatility factors of the expected market price of the Company's common stock of 48.94% and an expected life of 10 years, the life of the option. ** less than $(.01) per share (7) Commodity Derivative Instruments and Hedging Activities 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, swaps or options. All transactions are accounted for in accordance with requirements of SFAS No. 133 which the Company adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk activities. 11
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 - ----------------------------------------------------------------------------- (7) Commodity Derivative Instruments and Hedging Activities, Continued As of September 30, 2003, the Company recorded a derivative asset of approximately $8,000 for the fair market value of its derivative instruments designated as cash flow hedges and a corresponding gain in other comprehensive income. The realized net losses from hedging activities were $312,000 for the three months ended September 30, 2003. As of September 30, 2003, the Company had approximately 18,600 Bbls of oil subject to commodity price risk contracts for the remainder of fiscal 2004. The fiscal 2004 contract has weighted average floor prices of $28.13 per barrel with weighted average ceiling prices of $28.13 per barrel. (8) Comprehensive Income Comprehensive income (loss) includes all changes in equity during a period. The components of comprehensive income (loss) for the three months ended September 30, 2003 and 2002 are as follows: Three Months Ended Three Months Ended September 30, 2003 September 30, 2002 ----------------- ----------------- Net Income $1,364,000 $ 117,000 Other comprehensive income Change in fair value of derivative hedging instruments 476,000 (870,000) Unrealized gain (loss) on marketable securities $ (124,000) $ 88,000 ---------- ---------- Other comprehensive income 352,000 (782,000) Comprehensive income (loss) $1,716,000 $ (665,000) ========== ========== (9) Income Taxes For income tax purposes, the Company has net operating loss carryforwards expiring at various dates through 2023. As a result of the acquisitions and other issuances of stock, the utilization of the net operating loss carryforwards is subject to an annual limitation by the provisions of Section 382 of the Internal Revenue Code. The Company recognized no tax expense in the first quarter of fiscal 2004 primarily due to recognition of deferred tax assets for which a valuation allowance had previously been provided and recognized no tax benefit in fiscal 2003 because realization was not more likely than not. The remaining deferred tax asset at September 30, 2003, for which a valuation allowance has been recorded, will be recognized in the financial statements when its realization is more likely than not. 12
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES Notes to Consolidated Financial Statements Three Months Ended September 30, 2003 and 2002 - ----------------------------------------------------------------------------- (10) Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share: Three Months Ended September 30, 2003 2002 ---- ---- Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ 1,364,000 $ 117,000 ----------- ----------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 23,476,000 22,629,000 Effect of dilutive securities- stock options and warrants 1,648,000 2,584,000 ----------- ----------- Denominator for diluted earnings per common share 25,124,000 25,213,000 =========== =========== Basic earnings per common share $ .06 $ .01 =========== =========== Diluted earnings per common share $ .05 $ * =========== =========== Anti-dilutive securities outstanding 1,350,000 2,123,000 =========== =========== * less than $.01 per share (11) Commitments As of September 30, 2003, the Company had approximately 280 Bbls of oil per day of its offshore production under fixed price contracts. The contracts' fixed prices range from $25.50 to $29.70. (12) Reclassification Certain amounts in the 2002 financial statements have been reclassified to conform to the 2003 financial statement presentation. 13
Item 2. Management's Discussion and Analysis or Plan of Operations Forward Looking Statements -------------------------- 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 our actual results to differ materially from those expressed in such forward looking statements reported in our annual report on Form 10-K. These factors include, without limitation, the risks and factors included in the following text as well as other risks previously discussed in our annual report on Form 10-K. Critical Accounting Policies and Estimates ------------------------------------------ The discussion and analysis of the Company's financial condition and results of operations were based upon 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 1 to our consolidated financial statements included in our annual report on Form 10-K. In response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," 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, marketable securities, 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 the Company's 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. Gas and oil 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 that 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 14
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 incurred to select development locations within an oil and gas field is typically considered a development cost and 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 the Company is 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. 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, 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. We reevaluate our reserves quarterly. 15
Impairment of Gas and Oil Properties ------------------------------------ We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our 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 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 the Company to record an impairment of the recorded book values associated with gas and oil properties. The Company did not record an impairment during the three months ended September 30, 2003 and 2002. Commodity Derivative Instruments and Hedging Activities ------------------------------------------------------- We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize future contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative=s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management (CPRM) activities. 16
We account for our asset retirement obligations under SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. The Company=s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. Liquidity and Capital Resources ------------------------------- Liquidity is a measure of a company's ability to access cash. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities, when market conditions permit, and most recently through the use of a bank credit facility and cash provided by operating activities. The prices we receive for future oil and natural gas production and the level of production have significant impacts on 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. We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, sales of non-strategic assets, and joint venture financing. Availability of these alternative sources of capital will depend upon a number of factors, some of which are beyond our control. Working Capital --------------- Although we have a working capital deficit of $10,573,000 at September 30, 2003, we believe our cash flow will be sufficient to service our current obligation during our 2004 fiscal year. It is also possible, however, that we may obtain additional working capital from outside sources through the issuance of equity securities or from the sale of properties in the ordinary course of our business. Our current portion of long-term debt includes a monthly commitment of $640,000 relating to our credit facility and the entire Kaiser Francis note payable of $4,159,000 which is due on June 1, 2004. Cash Provided by Operating Activities ------------------------------------- During the three months ended September 30, 2003, we had cash provided by operating activities of $4,952,000 compared to cash used in operating activities of $3,155,000 during the same period ended September 30, 2002. This increase in operating activities is a result of the increase in oil and natural gas sales relating to the JAED acquisition completed during the fourth quarter of fiscal 2003. 17
Cash Used in Investing Activities --------------------------------- During the three months ended September 30, 2003, we had cash used in investing activities of $5,609,000 compared to cash used in investing activities of $970,000 during the same period ended September 30, 2002. Investing activities for fiscal 2004 included $2,000,000 used toward the acquisition of production and drilling prospects in Colorado and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, "Davis") and $3,743,000 for development activities. Investing activities for fiscal 2003 included approximately $1,139,000 for development costs. Cash Used In Financing Activities --------------------------------- During the three months ended September 30, 2003, we had cash used in financing activities of $116,000 compared to cash used in financing activities of $315,000 for the same period ended September 30, 2002. Financing activities for fiscal 2004 consist of proceeds from borrowings of $1,080,000, repayment of borrowings and financing costs of $1,587,000 and stock issued for cash upon exercise of options of $391,000. Financing activities for fiscal 2003 consist of repayment of borrowings and financing costs of $355,000 and stock issued for cash upon exercise of options of $40,000. Fiscal 2004 - Acquisition -------------------------- On September 19, 2003, the Company completed an acquisition of certain production and drilling prospects in Colorado and Wyoming from Davis, pursuant to the terms of a Purchase and Sale Agreement effective as of August 1, 2003. The total consideration paid for these properties was 1,000,000 shares of our common stock and $8 million, of which $2 million was paid in cash and $6 million in the form of a short-term promissory note payable on October 3, 2003. The shares issued were recorded at a price of $5.15, a five day coverage surrounding the announcement of the transaction. The Company recorded an upward purchase price adjustment of approximately $318,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of August 1, 2003 through the closing date of September 19, 2003. The total acquisition cost of $13,468,000 was allocated between proved developed producing of $6,318,000 and proved undeveloped of $7,150,000 based on preliminary information. We will also be obligated to issue additional shares of common stock to Davis in the event that it is determined that valid drillable prospects for the discovery and production of hydrocarbons on certain leases, or land pooled therewith, meet certain requirements, including a determination that there are at least 1,000,000 barrels of recoverable oil or six billion cubic feet of recoverable gas, or a combination thereof, in the prospect. These prospects are referred to as "Bonus Prospects." Davis will receive up to 190,000 (not more than $950,000 worth of stock) shares for each Bonus Prospect. No more than 1,900,000 shares will be issued to Davis under this provision, regardless of how many barrels of oil equivalent may be found. Davis also has the option to elect to take assignment of up to a 50% working interest in each well drilled on a Bonus Prospect after payout, on a well-by-well basis. 18
Fiscal 2004 Property Expenditures --------------------------------- We estimate our capital expenditures for onshore properties to range from $8.5 million to $15.7 million depending on drill rig availability and success of drilling programs for the year ending June 30, 2004. We anticipate that we will drill one to two developmental wells from the Point Arguello Unit platforms to the Rocky Point structure during fiscal 2004. Each well will cost approximately $10 million ($670,000 to our interest). We anticipate paying for all capital expenditures out of anticipated cash flow which assumes certain price levels for production. 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. Options ------- We received the proceeds from the exercise of options to purchase shares of our common stock of $391,000 and $975,000 during the three months ended September 30, 2003 and year ended June 30, 2003, respectively. Credit Facility --------------- We initially entered into our credit facility with Bank of Oklahoma and Local Oklahoma Bank ("Credit Facility") when we acquired all of the domestic oil and gas properties of Castle Energy Corporation. The Credit Facility, as amended as of October 1, 2003, provides for a maximum borrowing base of $34 million and a monthly commitment reduction of $640,000. The Credit Facility has a variable interest rate component of prime +1.5%/-.5% based on the total debt outstanding (currently at prime +.5%). As of September 30, 2003, we had outstanding borrowings of approximately $27,548,000 and letters of credit for Operator's Bonds outstanding of $550,000. Our borrowing base and monthly commitment reduction will be redetermined at least semi-annually. This determination will be based on our "Engineered Value." This value is determined by our future net revenues discounted at the discount rate used by the Bank of Oklahoma as of the date that the redetermination is made using the pricing parameters used in the engineering report that is furnished to the Bank of Oklahoma. The most recent redetermination was effective October 1, 2003. The foregoing does not purport to be a complete summary of the Credit Agreement and other loan documents. Complete copies of the original credit facility documents are filed as exhibits to our Report on Form 8-K dated May 24, 2002. Results of Operations for Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002 --------------------------------------------------------------- Net Earnings. Our net income for the three months ended September 30, 2003 was $1,364,000 compared to a net income of $117,000 for the three months ended September 30, 2002. The results for the three months ended September 30, 2003 and 2002 were affected by the items described in detail below. 19
Revenue. Total revenue for the three months ended September 30, 2003 was $7,444,000 compared to $5,434,000 for the three months ended September 30, 2002. Oil and gas sales for the three months ended September 30, 2003 were $7,756,000 compared to $5,467,000 for the three months ended September 30, 2002. The increase in oil and gas sales during the three months ended September 30, 2003 resulted from the JAED acquisition completed during the fourth quarter of fiscal 2003 and an increase in oil and gas prices. Production volumes and average prices received for the three months ended September 30, 2003 and 2002 are as follows: Three Months Ended September 30, 2003 2002 Onshore Offshore Onshore Offshore ------- -------- ------- -------- Production: Oil (barrels) 110,000 48,000 64,000 62,000 Gas (Mcf) 741,000 - 801,000 - Average Price: Oil (per barrel) $29.17 $21.96 $25.50 $ 20.03 Gas (per Mcf) $ 4.84 - $ 3.19 - Hedge Effect $(1.34) - $( .17) - (Per barrel equivalent) Lease Operating Expenses. Lease operating expenses for the three months ended September 30, 2003 were $2,326,000 compared to $2,069,000 for the three months ended September 30, 2002. Lease operating expense increased slightly compared to fiscal 2002 as a result of the JAED acquisition completed during fourth quarter fiscal 2003. On a per barrel ("Bbl") equivalent basis, production expenses and taxes were $6.42 for onshore properties and $17.30 for offshore properties during the three months ended September 30, 2003 compared to $6.67 for onshore properties and $14.60 for offshore properties for the three months ended September 30, 2002. Onshore costs per equivalent Bbl decreased slightly as production increased from the JAED acquisition which we closed at the end of fiscal 2003. JAED's operating costs are lower than the rest of Delta's property base. Offshore costs per equivalent Bbl increased as production declined by approximately 25% compared to the same period a year ago. The Company was just approved to drill the east half of lease 451 of our Rocky Point unit which will increase production and lower per Bbl equivalent costs. Depreciation and Depletion Expense. Depreciation and depletion expense for the three months ended September 30, 2003 was $1,692,000 compared to $1,685,000 for the three months ended September 30, 2002. On a per Bbl equivalent basis, the depletion rate was $6.41 for onshore properties and $3.68 for offshore properties during the three months ended September 30, 2003 compared to $6.91 for onshore properties and $4.83 for offshore properties for the three months ended September 30, 2002. 20
Exploration Expenses and Dry Hole Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $130,000 for the three months ended September 30, 2003 compared to $7,000 for the three months ended September 30, 2002. Exploration costs during the quarter ended September 30, 2003 included seismic costs relating to the Davis acquisition which closed on September 19, 2003. Professional Fees. Professional fees for the three months ended September 30, 2003 were $304,000 compared to $177,000 for the three months ended September 30, 2002. Professional fees consist of corporate, legal and accounting costs related to investor relations and 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 three months ended September 30, 2003 were $1,139,000 compared to $862,000 for the three months ended September 30, 2002. The increase in general and administrative expenses is primarily attributed to increased costs associated with the acquisitions completed in fiscal 2002 and 2003 including office expansion and additional staff. Interest and Financing Costs. Interest and financing costs for the three months ended September 30, 2003 were $509,000 compared to $508,000 for the three months ended September 30, 2002. Interest expense stayed consistent as the increase in long term debt was offset by a reduction in interest rates. Income Taxes - ------------ The Company recognized no tax expense in 2004 primarily due to recognition of deferred tax assets for which a valuation allowance had previously been provided and recognized no tax benefit in 2002 because realization was not more likely than not. The remaining deferred tax asset at September 30, 2003, for which a valuation allowance has been recorded, will be recognized in the financial statements when its realization is more likely than not. Item 3. Quantitative and Qualitative Disclosures About 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. Market Rate and Price Risk -------------------------- Beginning in fiscal 2003, we began to hedge a portion of our oil and gas production using swap and collar agreements. The purpose of these agreements is to provide a measure of stability to our cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. 21
Interest Rate Risk ------------------ We were subject to interest rate risk on $37,707,000 of variable rate debt obligations at September 30, 2003. The annual effect of a one percent change in interest rates would be approximately $377,000. The interest rate on these variable rate debt obligations approximates current market rates as of September 30, 2003. Item 4. Controls and Procedures As of September 30, 2003, under the supervision and with the participation of the Company's Chief Executive Officer and the Chief Financial Officer, management has evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of September 30, 2003. 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 affect, the Company's internal control over financial reporting. PART II - OTHER INFORMATION Item 1. Legal Proceedings. On January 9, 2002, we 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 our 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 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 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. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152,000,000. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties. Although the computation of the various amounts that we would be required to pay to landowners and other owners of royalties and similar interests is dependent upon facts and circumstances that are not yet known, it is possible that they may be as much as twenty percent of any proceeds that we might ultimately obtain. 22
The Federal Government has not yet filed an answer in this proceeding pending its motion to dismiss the lawsuit, which motion has not yet been heard by the court. Item 2. Changes in Securities. During the quarter ended September 30, 2003, we issued securities in transactions that were not registered under the Securities Act of 1933 as follows: On July 11, 2003, Swartz Private Equity, LLC ("Swartz") exercised 27,000 options in a cashless exercise transaction, which was permitted in our investment agreement with Swartz. As a result of the exercise, Swartz received 9,352 shares of our common stock. On September 19, 2003, we issued 1,000,000 shares of our common stock to Edward Mike Davis in connection with the acquisition of certain production and drilling prospects in Colorado and Wyoming. In connection with these transactions we relied on the exemption provided by Section 4(2) of the Securities Act of 1933. We reasonably believe that both of the investors are "Accredited Investors" as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act of 1933 at the time the transactions occurred. The investors acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the investors, and stop transfer orders were given to our transfer agent. 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 are as follows: 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. Filed herewith electronically (b) Reports on Form 8-K. During the quarter ended September 30, 2003, Delta filed Reports on Form 8-K as follows: 1. Report on Form 8-K/A dated June 30, 2003 reporting information under Item 5 and Item 7, filed on July 1, 2003. 2. Report on Form 8-K dated September 22, 2003 reporting information under Item 7 and Item 9, filed on September 23, 2003. 3. Report on Form 8-K dated September 19, 2003 reporting information under Item 2, filed on October 2, 2003. 23
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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/ 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: November 5, 2003 24