Exhibit 99.1
DELTA PETROLEUM CORPORATION
Roger A. Parker, Chairman and CEO
John R. Wallace, President and COO
Kevin K. Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202
Roger A. Parker, Chairman and CEO
John R. Wallace, President and COO
Kevin K. Nanke, Treasurer and CFO
Broc Richardson, V.P. Corporate Development and IR
370 17th Street, Suite 4300
Denver, Colorado 80202
For Immediate Release
DELTA PETROLEUM CORPORATION
ANNOUNCES FIRST QUARTER 2009 OPERATING RESULTS
ANNOUNCES FIRST QUARTER 2009 OPERATING RESULTS
DENVER, Colorado (May 5, 2009) — Delta Petroleum Corporation (NASDAQ Global Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the first quarter of 2009.
Roger Parker, the Company’s Chairman and CEO stated, “Delta’s financial results for the first quarter continued to reflect depressed commodity prices. However, numerous steps have been taken to reposition the Company for the current industry environment. During the first quarter we laid down our last operating drilling rig on our Piceance Basin properties in order to significantly reduce 2009 drilling capital expenditures. Additional cost control initiatives implemented at the end of the quarter include a more than one-third reduction in personnel and a 20% salary reduction for executive officers, directors and certain members of senior management. Other general and administrative expenses have been reduced and should continue to decline during the balance of the year. Benefits from our cost-cutting efforts should be evident in the Company’s second quarter financial results.”
“Lease Operating Expenses (LOE) were temporarily higher than normal during the first quarter as we wound down drilling activity in the Piceance Basin, but a significant portion of these costs have since been eliminated. Substantial reductions in LOE were apparent in the month of April, when compared with the first quarter monthly average. As an example, storage tank rentals have decreased from 240 to 120 tanks, and most of the produced water held in those tanks has been hauled and disposed. Third party service contractor charges have also declined over 20% in the past few months, and the availability of company-owned disposal wells and a new water distillation facility will further reduce LOE as the year progresses.”
“We are taking necessary actions to improve our liquidity position, which has been assisted by the positive outcome of a portion of our Offshore California litigation. The United States government has acknowledged that approximately $56.6 million of the $60 million judgment is being processed for payment, and we expect to receive these funds in the near future,” continued Parker. “Ultimately, the Company will receive $48.7 million after payment of certain contractual obligations and overriding royalty payables, and $27.9 million of this amount will be paid to Tracinda Corporation in accordance with a previously disclosed Contingent Payment Rights Purchase Agreement. The Company has a $91.4 million additional judgment against the government, and we are reviewing our options related to this litigation as well. Meanwhile, we have continued to operate under the terms of our Forbearance Agreement with the support of our lending group and have been granted extensions to allow for the review and consideration of various strategic and capital formation alternatives that should alleviate our current liquidity constraints.”
“Operationally, numerous wells that have been drilled and cased in the Piceance Basin will be completed in coming months, and this should allow for consistent production when compared with prior-year levels. Drilling and completion costs have declined significantly, and these cost savings should enhance the economics of development in the area. Earlier this decade, when drilling and completion costs were lower, very
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economic rates of return were achieved in predictable development areas like the Piceance Basin at commodity prices near current levels. We remain confident in the long-term value of our proven assets in the Piceance.”
“In the Columbia River Basin,” added Parker, “we are approaching total depth on our Gray well and believe the potential for the well and the project could have a significant impact on the Company’s shareholder value.”
RESULTS FOR THE FIRST QUARTER
For the quarter ended March 31, 2009, the Company reported production of 6.32 billion cubic feet equivalents (Bcfe), an increase of 18% when compared with the first quarter of 2008. Total revenue decreased 9% to $58.7 million in the quarter, including a gain of $31.3 million from our offshore litigation, versus revenue of $64.5 million in the quarter ended March 31, 2008. Revenue from oil and gas sales declined 59% to $22.1 million, compared with $53.8 million in the prior-year quarter. The decrease was primarily due to a 61% reduction in average realized gas prices and a 65% decrease in average realized oil prices, partially offset by an 18% increase in total production. Revenue from contract drilling and trucking fees decreased 51% to $5.2 million in the most recent quarter, versus $10.7 million in the first quarter of 2008, due to lower rig utilization. As a result of the drop in commodity prices when compared with the prior-year quarter, EBITDAX decreased to ($415,000). (Note: EBITDAX and Discretionary Cash Flow are non-GAAP measures that are described in greater detail below.)
The Company reported a first quarter net loss attributable to common stockholders of ($25.6 million), or ($0.25) per share, compared with a net loss attributable to common stockholders of ($20.8 million), or ($0.26) per share, in the first quarter of 2008.
FIRST QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per thousand cubic feet equivalents (Mcfe) for the three months ended March 31, 2009 and 2008 are as follows:
Three Months Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
Production — Continuing Operations: | ||||||||
Oil (MBbl) | 212 | 266 | ||||||
Gas (MMcf) | 5,050 | 3,768 | ||||||
Total Production (MMcfe) | 6,324 | 5,367 | ||||||
Average Price — Continuing Operations: | ||||||||
Oil (per barrel) | $ | 31.44 | $ | 91.09 | ||||
Gas (per Mcf) | $ | 3.07 | $ | 7.83 | ||||
Costs per Mcfe — Continuing Operations: | ||||||||
Lease operating expense | $ | 1.56 | $ | 1.51 | ||||
Production taxes | $ | .25 | $ | .66 | ||||
Transportation costs | $ | .51 | $ | .34 | ||||
Depletion expense | $ | 4.13 | $ | 4.19 | ||||
Realized derivative losses | $ | — | $ | (0.30 | ) |
Lease operating expense.Lease operating expense for the quarter ended March 31, 2009 increased to $9.8 million from $8.1 million in the year-earlier period. Lease operating expense from continuing operations for the three months ended March 31, 2009 increased to $1.56 per Mcfe from $1.51 per Mcfe for the comparable
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period in 2008. The increase was primarily due to increased water disposal in the Piceance Basin during a period of reduced drilling and completion activity. The Company has historically utilized most of the water produced by wells in its completion activities. However with the reduction in completion activity, the stored water was hauled away and disposed. The Company expects lease operating expense to decline with the availability of newly drilled water disposal wells and the future implementation of a water distillation facility. Lease operating expenses should decrease more than 25% in the Vega Area of the Piceance Basin once these facilities have been approved and installed.
Depreciation, depletion and amortization expense.Oil and gas depreciation, depletion and amortization expense increased 16% to $26.8 million in the three months ended March 31, 2009, compared with $23.0 million in the comparable year-earlier period. Depletion expense totaled $26.1 million in the most recent quarter, compared with $22.5 million in the three months ended March 31, 2008. The increase in depletion expense was due to higher production from continuing operations, slightly offset by lower depletion rates. The depletion rate decreased from $4.19 per Mcfe in last year’s first quarter to $4.13 per Mcfe in the current-year period, primarily due to the effect of impairments recorded in the fourth quarter of 2008, partially offset by the effect of low spot commodity prices at March 31, 2009 on the depletion calculation. The Company expects future depletion rates to decrease if commodity prices increase.
General and administrative expense.General and administrative expense decreased 6% to $12.6 million in the three months ended March 31, 2009, compared with $13.4 million in the prior-year quarter. The decrease in general and administrative expense was primarily attributed to a decrease in non-cash stock compensation expense resulting from lower executive performance share costs, and from forfeitures and modifications related to a reduction in force in early March 2009 that affected approximately one-third of the Company’s personnel. Further reductions in cash general and administrative costs should result from the reduction in force, along with a 20% salary reduction for executive officers, directors and much of the Company’s senior management team that was implemented at the end of the first quarter. Based upon initial results for the month of April, the Company expects second quarter cash general and administrative expenses to decline by 20%-25% from first quarter levels with further reductions expected throughout 2009.
LIQUIDITY AND OUTLOOK
On March 2, 2009, Delta entered into a Forbearance Agreement and Amendment to its credit agreement pursuant to which the lenders under the credit facility agreed to forbear from taking certain actions (including accelerating amounts due under the credit facility) as a result of violations of certain covenants under the credit agreement. In addition, the agreement amended Delta’s 2009 debt-to-EBITDAX covenant to a senior secured debt-to-EBITDAX covenant, reducing the borrowing base from $295.0 million to $225.0 million and thereby requiring Delta to repay the $70.0 million borrowed in excess of the borrowing base, as discussed below, and increased the variable interest rates payable. The Forbearance Agreement and Amendment to the credit agreement requires that the Company raise net proceeds of at least $140.0 million through capital raising efforts on or before the forbearance termination date, which was extended on April 14, 2009 and again on April 30, 2009 to a current forbearance termination date of May 15, 2009 at which time a minimum of $70 million in net proceeds must be raised with the balance to be raised by June 15, 2009.
During the quarter ended March 31, 2009, the Company had an operating loss of $9.0 million, net cash used in operating activities of $5.9 million and net cash provided by financing activities of $13.8 million. During this period Delta’s drilling capital expenditures were approximately $29.4 million. At March 31, 2009, the Company had $24.5 million in cash, total assets of $1.9 billion and a debt to capitalization ratio of 45.5%. Debt (excluding installments payable on property acquisition which are secured by restricted cash deposits) at March 31, 2009 totaled $637.7 million, comprised of $387.4 million of bank debt (all of which was classified as a current liability at March 31, 2009), $149.6 million of senior subordinated notes and $100.7 million of senior convertible notes. In accordance with applicable accounting rules, the senior convertible notes are recorded at a discount to its stated amount due of $115.0 million.
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ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Company’s open derivative contracts at March 31, 2009:
Commodity | Volume | Fixed Price | Term | Index Price | ||||||||||||||||||||
Crude oil | 1,000 | Bbls / Day | $ | 52.25 | Jul ’09 | - Dec ’09 | NYMEX – WTI | |||||||||||||||||
Crude oil | 1,000 | Bbls / Day | $ | 52.25 | Jan ’10 | - Dec ’10 | NYMEX – WTI | |||||||||||||||||
Crude oil | 500 | Bbls / Day | $ | 57.70 | Jan ’11 | - Dec ’11 | NYMEX – WTI | |||||||||||||||||
Natural gas | 4,000 | MMBtu / Day | $ | 5.720 | Aug ’09 | - Dec ’09 | NYMEX – HHUB | |||||||||||||||||
Natural gas | 6,000 | MMBtu / Day | $ | 5.720 | Jan ’10 | - Dec ’10 | NYMEX – HHUB | |||||||||||||||||
Natural gas | 10,000 | MMBtu / Day | $ | 4.105 | Aug ’09 | - Dec ’09 | CIG | |||||||||||||||||
Natural gas | 15,000 | MMBtu / Day | $ | 4.105 | Jan ’10 | - Dec ’10 | CIG | |||||||||||||||||
Natural gas | 4,373 | MMBtu / Day | $ | 3.973 | Aug ’09 | - Dec ’09 | CIG | |||||||||||||||||
Natural gas | 5,367 | MMBtu / Day | $ | 3.973 | Jan ’10 | - Dec ’10 | CIG | |||||||||||||||||
Natural gas | 12,000 | MMBtu / Day | $ | 5.150 | Jan ’11 | - Dec ’11 | CIG | |||||||||||||||||
Natural gas | 3,253 | MMBtu / Day | $ | 5.040 | Jan ’11 | - Dec ’11 | CIG |
The net fair value of the Company’s derivative instruments recorded in the financial statement was a liability of approximately $5.5 million at March 31, 2009. The Company currently has hedges representing approximately 40% of its anticipated production for the last two quarters of 2009, 70% of calendar 2010, and 50% of calendar 2011 under executed derivative contracts in accordance with the Forbearance Agreement and Amendment.
OPERATIONS UPDATE
Piceance Basin, CO, 31% — 100% WI —The Company ceased its drilling program in the Vega Area in February, but has continued its completion activity on a limited basis. As of December 31, 2008 the Company had 35 drilled but not yet completed wells. The inventory of uncompleted wells currently stands at 31. During the first quarter, the Company experienced an approximately 25% reduction in completion costs. Similarly, although the Company is not currently drilling, the cost for drilling new wells has decreased over 30%. Due to the slowdown in drilling and completion activity throughout the Rocky Mountain region, it is expected that capital costs will decline further, approaching the cost structure that was experienced earlier this decade when development drilling in the Piceance Basin was economic in a comparable gas price environment. Current production from the Piceance Basin approximates 51.5 million cubic feet equivalents per day (Mmcfe/d) gross and 41.5 Mmcfe/d net.
The Company is continuing with the permitting process for a new water treatment facility that is anticipated to significantly reduce water hauling and disposal costs for the field. The new water treatment facility is a patented distillation process that will allow the Company to surface discharge its treated water, thereby reduce field lease operating expenses substantially. The Company has ongoing discussions related to potential joint venture transactions for these assets.
Columbia River Basin, WA, 50% WI — The Company expects completion activities to commence on the Gray 31-23 well in the next several weeks. The Company has encountered and logged numerous highly porous and permeable gas-charged sands during in the drilling of the well. Although no additional capital commitments will be made until production and testing results from the well have been obtained, the Company has commenced permitting activities for at least two new wells in the Bronco prospect. Additionally, the Company has started the permitting process and rights-of-way procurement for a pipeline designed to transport gas 9 miles to the south and interconnect with a 26-inch main line.
Other Areas — For 2009 the Company has not allocated capital expenditures to other important areas of ownership which include the Paradox Basin, Utah Hingeline and Haynesville. However, efforts continue to progress to establish joint venture relationships with other companies for all areas. Additionally, there is current third party activity in close proximity to existing Company leasehold in each area.
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CALIFORNIA OFFSHORE LITIGATION
The Company has been awarded damages from the United States government in two separate judgments rendered at different times in the amounts of $60.0 million and $91.4 million, respectively, in a breach of contract case involving oil and gas leases that are located offshore California. The two judgments are at different stages of the litigation process. When the government did not seek Supreme Court review of the $60.0 million judgment after it was affirmed on appeal, the Company and the other plaintiffs in the case filed a motion with the United States Court of Federal Claims requesting an order requiring the government to file its certifications with the Department of the Treasury within ten days after the Court issues its order enforcing the judgment and requiring that the judgment be paid within fourteen days thereafter. The government is attempting to delay payment of $3.4 million of the amount due to the Company but has informed the Court that $56.6 million due to the Company is currently being processed for payment. A hearing on the motion related to the $3.4 million portion has been set for May 6, 2009. The Company has recorded the $60.0 million offshore litigation award as a receivable on its balance sheet as of March 31, 2009. The second judgment in the amount of $91.4 million was not rendered until February 25, 2009 and is currently being appealed by the government.
2009 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
As previously stated, the Company’s 2009 drilling capital expenditures should approximate $52 million, of which $29.4 million was incurred in the first quarter. The revised budget is primarily allocated to completion activities in the Piceance Basin and the remaining cost of drilling and testing the Gray well in the Columbia River Basin. With operational control over its asset base, no significant drilling obligations and minimal leasehold expirations, the Company should be able to maintain ownership of its core assets. Drilling capital expenditures for the month of April 2009 approximated $5.0 million, of which approximately $1.5 million was related to activity on the Columbia River Basin well which is very close to total depth.
The Company reaffirms its previously announced expectation that full year 2009 production should be equivalent to 2008 levels.
INVESTOR CONFERENCE CALL
An investor conference call has been scheduled for 8:30 am Eastern Time on Wednesday, May 6, 2009. Shareholders and other interested parties may participate in the conference call by dialing 800-860-2442 (international callers dial 412-858-4600) and asking to participate in the “Delta Petroleum Conference Call”, a few minutes before 8:30 am Eastern Time on May 6, 2009. The call will also be broadcast live and can be accessed through the Company’s website at http://www.deltapetro.com/eventscalendar.html. A replay of the conference call will be available two hours after the completion of the conference call from May 6, 2009 until May 14, 2009 by dialing 877-344-7529 and entering the conference ID 430227.
ABOUT DELTA PETROLEUM
Delta Petroleum Corporation is an oil and gas exploration and development company based in Denver, Colorado. The Company’s core areas of operations are the Rocky Mountain and Gulf Coast Regions, which comprise the majority of its proved reserves, production and long-term growth prospects. Its common stock is listed on the NASDAQ Global Market System under the symbol “DPTR.”
FORWARD-LOOKING STATEMENTS
Forward-looking statements in this announcement are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, without limitation, results and timing of cost cutting efforts, liquidity requirements, drilling activity, expected decreases in costs, depletion rates and lease operating expenses and general and administrative expenses, expectations regarding ownership of assets and anticipated drilling and production results for 2009. Readers are cautioned that all forward-looking statements are based on management’s present expectations, estimates and projections, but involve risks and uncertainty, including without limitation, uncertainties in the projection of future rates of production, unanticipated recovery or production problems, unanticipated results from wells being drilled or completed, the effects of delays in completion of gas gathering systems, pipelines and processing facilities, as well as general market conditions, competition and pricing. Please refer to the Company’s report onForm 10-K for the year ended December 31, 2008 and subsequent reports on Forms 10-Q and 8-K as filed with the Securities and Exchange Commission for additional information. The Company is under no obligation (and expressly disclaims any obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise.
For further information contact the Company at (303) 293-9133 or via email atinfo@deltapetro.com
or
RJ Falkner & Company, Inc., Investor Relations Counsel, at (800) 377-9893 or via email atinfo@rjfalkner.com
SOURCE: Delta Petroleum Corporation
or
RJ Falkner & Company, Inc., Investor Relations Counsel, at (800) 377-9893 or via email atinfo@rjfalkner.com
SOURCE: Delta Petroleum Corporation
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DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
(In thousands, except share data) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 24,506 | $ | 65,475 | ||||
Short-term restricted deposit | 100,000 | 100,000 | ||||||
Trade accounts receivable, net of allowance for doubtful accounts of $643 and $652, respectively | 18,760 | 30,437 | ||||||
Offshore litigation award receivable | 60,023 | — | ||||||
Deposits and prepaid assets | 5,202 | 11,253 | ||||||
Inventories | 11,526 | 9,140 | ||||||
Derivative instruments | 425 | — | ||||||
Deferred tax assets | — | 231 | ||||||
Other current assets | 5,783 | 6,221 | ||||||
Total current assets | 226,225 | 222,757 | ||||||
Property and equipment: | ||||||||
Oil and gas properties, successful efforts method of accounting: | ||||||||
Unproved | 398,937 | 415,573 | ||||||
Proved | 1,395,778 | 1,365,440 | ||||||
Drilling and trucking equipment | 194,843 | 194,223 | ||||||
Pipeline and gathering systems | 91,823 | 86,076 | ||||||
Other | 29,244 | 29,107 | ||||||
Total property and equipment | 2,110,625 | 2,090,419 | ||||||
Less accumulated depreciation and depletion | (691,981 | ) | (658,279 | ) | ||||
Net property and equipment | 1,418,644 | 1,432,140 | ||||||
Long-term assets: | ||||||||
Long-term restricted deposit | 200,000 | 200,000 | ||||||
Marketable securities | 1,977 | 1,977 | ||||||
Investments in unconsolidated affiliates | 18,103 | 17,989 | ||||||
Deferred financing costs | 5,807 | 7,640 | ||||||
Other long-term assets | 14,529 | 12,460 | ||||||
Total long-term assets | 240,416 | 240,066 | ||||||
Total assets | $ | 1,885,285 | $ | 1,894,963 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Credit facility — Delta | $ | 293,800 | $ | 294,475 | ||||
Credit facility — DHS | 93,648 | — | ||||||
Installments payable on property acquisition | 98,083 | 97,453 | ||||||
Accounts payable | 139,632 | 159,024 | ||||||
Offshore litigation award payable | 26,223 | — | ||||||
Other accrued liabilities | 16,608 | 13,576 | ||||||
Total current liabilities | 667,994 | 564,528 | ||||||
Long-term liabilities: | ||||||||
Installments payable on property acquisition, net of current portion | 189,552 | 188,334 | ||||||
7% Senior notes | 149,553 | 149,534 | ||||||
33/4% Senior convertible notes | 100,682 | 99,616 | ||||||
Credit facility — DHS | — | 93,848 | ||||||
Asset retirement obligations | 6,998 | 6,585 | ||||||
Derivative instruments | 5,889 | — | ||||||
Deferred tax liabilities | — | 1,024 | ||||||
Total long-term liabilities | 452,674 | 538,941 | ||||||
Commitments and contingencies | ||||||||
Equity: | ||||||||
Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued | — | — | ||||||
Common stock, $.01 par value; authorized 300,000,000 shares, issued 102,822,000 shares at March 31, 2009 and 103,424,000 shares at December 31, 2008 | 1,028 | 1,034 | ||||||
Additional paid-in capital | 1,374,561 | 1,372,123 | ||||||
Treasury stock at cost; 35,000 shares at March 31, 2009 and 36,000 shares at December 31, 2008 | (453 | ) | (540 | ) | ||||
Accumulated deficit | (635,781 | ) | (610,227 | ) | ||||
Total Delta stockholders’ equity | 739,355 | 762,390 | ||||||
Non-controlling interest | 25,262 | 29,104 | ||||||
Total equity | 764,617 | 791,494 | ||||||
Total liabilities and equity | $ | 1,885,285 | $ | 1,894,963 | ||||
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DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
(In thousands, except per share amounts) | ||||||||
Revenue: | ||||||||
Oil and gas sales | $ | 22,158 | $ | 53,760 | ||||
Contract drilling and trucking fees | 5,213 | 10,720 | ||||||
Gain on offshore litigation award | 31,285 | — | ||||||
Total revenue | 58,656 | 64,480 | ||||||
Operating expenses: | ||||||||
Lease operating expense | 9,846 | 8,091 | ||||||
Transportation expense | 3,255 | 1,823 | ||||||
Production taxes | 1,580 | 3,541 | ||||||
Exploration expense | 1,060 | 1,002 | ||||||
Dry hole costs and impairments | 1,443 | 2,339 | ||||||
Depreciation, depletion, amortization and accretion — oil and gas | 26,822 | 23,039 | ||||||
Drilling and trucking operating expenses | 5,256 | 6,823 | ||||||
Depreciation and amortization — drilling and trucking | 5,792 | 3,643 | ||||||
General and administrative | 12,630 | 13,421 | ||||||
Total operating expenses | 67,684 | 63,722 | ||||||
Operating income (loss) | (9,028 | ) | 758 | |||||
Other income and (expense): | ||||||||
Interest expense and financing costs | (17,074 | ) | (8,937 | ) | ||||
Interest income | 648 | 1,870 | ||||||
Other income (expense) | 154 | 457 | ||||||
Realized loss on derivative instruments, net | — | (1,635 | ) | |||||
Unrealized loss on derivative instruments, net | (5,464 | ) | (14,133 | ) | ||||
Income (loss) from unconsolidated affiliates | 747 | (108 | ) | |||||
Total expense | (20,989 | ) | (22,486 | ) | ||||
Loss from continuing operations before income taxes and discontinued operations | (30,017 | ) | (21,728 | ) | ||||
Income tax benefit | (583 | ) | (597 | ) | ||||
Loss from continuing operations | (29,434 | ) | (21,131 | ) | ||||
Discontinued operations: | ||||||||
Gain on sale of discontinued operations, net of tax | — | 20 | ||||||
Net loss | (29,434 | ) | (21,111 | ) | ||||
Less net loss attributable to non-controlling interest | 3,880 | 329 | ||||||
Net loss attributable to Delta common stockholders | $ | (25,554 | ) | $ | (20,782 | ) | ||
Amounts attributable to Delta common stockholders: | ||||||||
Loss from continuing operations | $ | (25,554 | ) | $ | (20,802 | ) | ||
Income (loss) from discontinued operations, net of tax | — | 20 | ||||||
Net loss | $ | (25,554 | ) | $ | (20,782 | ) | ||
Basic income (loss) attributable to Delta common stockholders per common share: | ||||||||
Loss from continuing operations | $ | (0.25 | ) | $ | (0.26 | ) | ||
Discontinued operations | — | — | ||||||
Net loss | $ | (0.25 | ) | $ | (0.26 | ) | ||
Diluted income (loss) attributable to Delta common stockholders per common share: | ||||||||
Loss from continuing operations | $ | (0.25 | ) | $ | (0.26 | ) | ||
Discontinued operations | — | — | ||||||
Net loss | $ | (0.25 | ) | $ | (0.26 | ) | ||
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DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(in thousands) | ||||||||
(unaudited) | ||||||||
March 31, | March 31, | |||||||
THREE MONTHS ENDED: | 2009 | 2008 | ||||||
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | $ | (5,908 | ) | $ | 7,097 | |||
Changes in assets and liabilities | (7,508 | ) | 20,486 | |||||
Exploration and dry hole costs | 1,060 | 1,270 | ||||||
Discretionary cash flow (deficiency)* | $ | (12,356 | ) | $ | 28,853 | |||
* | Discretionary cash flow represents net cash provided by (used in) operating activities before changes in assets and liabilities plus exploration costs. Discretionary cash flow is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Discretionary cash flow is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. |
March 31, | March 31, | |||||||
THREE MONTHS ENDED: | 2009 | 2008 | ||||||
Net loss attributable to Delta common stockholders | $ | (25,554 | ) | $ | (20,782 | ) | ||
Income tax expense (benefit) | (583 | ) | (597 | ) | ||||
Interest income | (648 | ) | (1,870 | ) | ||||
Interest and financing costs | 17,074 | 8,937 | ||||||
Depletion, depreciation and amortization | 32,614 | 26,682 | ||||||
Gain on offshore litigation award and other | (31,285 | ) | (20 | ) | ||||
Unrealized loss on derivative instruments | 5,464 | 14,133 | ||||||
Exploration and dry hole costs | 2,503 | 3,341 | ||||||
EBITDAX** | $ | (415 | ) | $ | 29,824 | |||
March 31, | March 31, | |||||||
THREE MONTHS ENDED: | 2009 | 2008 | ||||||
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | $ | (5,908 | ) | $ | 7,097 | |||
Changes in assets and liabilities | (7,508 | ) | 20,486 | |||||
Interest net of financing costs | 10,328 | 4,688 | ||||||
Exploration and dry hole costs | 1,060 | 1,270 | ||||||
Other non-cash items | 1,613 | (3,717 | ) | |||||
EBITDAX** | $ | (415 | ) | $ | 29,824 | |||
** | EBITDAX represents net income (loss) attributable to Delta common stockholders before income tax expense (benefit), interest and financing costs, depreciation, depletion and amortization expense, gain on sale of oil and gas properties and other investments, unrealized gains (loss) on derivative contracts and exploration and impairment and dry hole costs. EBITDAX is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. EBITDAX is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by (used in) operating activities prepared in accordance with GAAP. |
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