DENVER, Aug. 9 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation (the "Company" or "Delta") , an independent oil and gas exploration and development company, today announced its financial and operating results for the second quarter of 2010.
Carl Lakey, Delta's President and CEO, stated, "The second quarter for 2010 was a pivotal period for Delta Petroleum. We have now completed our strategic alternatives process and have begun analyzing the results from earlier changes in the well completion process in the Piceance Basin. The new completion technique is generating results that are better than expected. Although we are still early in the evaluation process, the results to date do suggest using the new technique on all 15 remaining wells.
"After the end of the quarter, we received approximately $130 million in gross proceeds from the sale to Wapiti Oil & Gas of certain non-core properties that amounted to approximately 25% of our total proved reserves at year end 2009. With the proceeds from this transaction, we have reduced our credit facility borrowings to very minimal levels and we are now in the process of obtaining a new credit facility that we expect to have in place by the end of the third quarter. We will continue to stringently focus on cost control and efficient operations in the Vega area and are confident that we will be able to create value in doing so."
$130 MILLION ASSET DIVESTITURE
As previously announced, the Company closed on its $130 million non-core asset sale with Wapiti Oil & Gas, L.L.C. ("Wapiti") on July 30, 2010 (the "Wapiti Transaction"). Of the $130 million purchase price, $112 million was received by the Company at closing and used to reduce bank debt and to pay transaction costs. The remaining $18 million is being held in escrow until third party consents are obtained for the assignment of the Company's working interest in certain properties that were a part of the transaction. The Company expects to receive the consents and escrowed funds during the third quarter of 2010, and upon receipt, such funds will also be used to reduce debt.
In accordance with applicable accounting standards, properties held for sale at June 30, 2010 in conjunction with the Wapiti Transaction in which the Company only sold half of its interest continue to be reported as a component of continuing operations and are primarily comprised of the Newton and Midway Loop fields. The fields classified as discontinued operations are fields in which the Company sold all of its interest and include the 31% working interest in the Garden Gulch field, the Baffin Bay field, and the Bull Canyon field, as well as the Company's interest in its wholly-owned subsidiary, Piper Petroleum.
The Company recorded impairment losses associated with assets held for sale during the three months ended June 30, 2010 of $96.1 million, of which $92.2 million was included in loss from discontinued operations and $3.9 million was included in dry holes and impairments. The Company expects to recognize a gain on sale for the closing of the Wapiti Transaction in the three months ending September 30, 2010 of approximately $29.4 million, subject to revision for normal and customary purchase price adjustments as provided for under the purchase and sale agreement. In total, the Wapiti Transaction is expected to result in a $66.7 million loss when the second quarter asset held for sale impairments are considered in conjunction with the third quarter gain on sale.
See Reconciliation of Non-GAAP Measures below for a reconciliation of non-GAAP measures to the GAAP measures each as provided herein.
LIQUIDITY UPDATE
On July 23, 2010, the Company and its credit facility banks agreed to amend the credit agreement for its senior credit facility. As a result of the new amendment and the completion of the Wapiti Transaction, the Company's borrowing base was reduced to $35 million. The amendment imposed capital expenditures limitations of $18 million for the third quarter 2010 and $10 million for the fourth quarter 2010 with a carry-over provision and eliminated all scheduled or special borrowing base redeterminations prior to the maturity of the facility in January 2011.
The Company was in compliance with its financial ratio, capital expenditures and accounts payable covenants under its credit facility as of June 30, 2010.
At July 30, 2010, the Company held approximately $10 million in cash after paying transaction costs on the Wapiti sale and $18 million held in escrow pending third party consents. Based on the revised borrowing base and the completion of the Wapiti Transaction, $11 million was available for borrowing under the amended credit facility, giving the Company approximately $40 million in liquidity.
RESULTS FOR THE SECOND QUARTER
The Company reported a second quarter net loss attributable to common stockholders of ($149.8 million), or ($0.54) per share, compared with a net loss attributable to common stockholders of ($172.3 million), or ($0.89) per share, in the second quarter of 2009. The net loss attributable to common stockholders for the second quarter 2010 includes a $96.1 million impairment charge associated with the assets held for sale.
For the quarter ended June 30, 2010, the Company reported production of 4.7 billion cubic feet equivalents ("Bcfe"). Approximately 1.3 Bcfe of production in the quarter was from assets sold in the Wapiti Transaction, of which 795 Mmcfe is accounted for under "Discontinued Operations". The following discussion is on a "Continuing Operations" basis.
Total revenue increased 73% to $36.0 million in the quarter, versus revenue of $20.9 million in the quarter ended June 30, 2009. The increase is primarily related to a $9.4 million increase in contract drilling and trucking fees, improved third party rig utilization, and a $5.8 million quarter-over-quarter increase in oil and gas sales. For the quarter ended June 30, 2010, oil and gas sales increased 30% to $25.1 million, as compared to $19.3 million for the prior year period. The increase was primarily the result of a 110% increase in natural gas prices and a 31% increase in oil prices, partially offset by a 21% decrease in production. The average natural gas price received during the quarter ended June 30, 2010 increased to $4.86 per thousand cubic feet ("Mcf") compared to $2.31 per Mcf for the prior year period. The average oil price received during the quarter ended June 30, 2010 increased to $69.88 per barrel ("Bbl") compared to $53.22 per Bbl for the prior year period.
SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent Mcf for the three months ended June 30, 2010 and 2009 are as follows:
Three Months Ended June 30, -------- 2010 2009 ---- ---- Production - Continuing Operations: Oil (Mbbl) 150 198 Gas (Mmcf) 3,004 3,776 Total Production (Mmcfe) - Continuing Operations 3,902 4,964 Average Price - Continuing Operations: Oil (per barrel) $69.88 $53.22 Gas (per Mcf) $4.86 $2.31 Costs (per Mcfe) - Continuing Operations: Lease operating expense $2.05 $1.38 Transportation expense $1.14 $0.44 Production taxes $0.35 $0.21 Depletion expense $3.82 $4.66 Realized derivative losses (per Mcfe) $0.15 $-
Lease Operating Expense. Lease operating expenses for the quarter ended June 30, 2010 increased to $8.0 million from $6.8 million in the year earlier period primarily due to increased water handling costs in the Vega area partially offset by lower offshore lease operating costs. Lease operating expense per Mcfe for the quarter ended June 30, 2010 increased to $2.05 per Mcfe from $1.38 per Mcfe. The quarter-over-quarter increase on a per unit basis was primarily due to the increased water handling costs in the Vega area and the effect of fixed costs spread over a 21% decline in production volumes.
Transportation Expense. Transportation expense for the quarter ended June 30, 2010 increased to $4.5 million from $2.2 million in the prior year. Transportation expense per Mcfe for the quarter ended June 30, 2010 increased 159% to $1.14 per Mcfe from $0.44 per Mcfe. The increase on a per unit basis is primarily the result of changes to the Company's Vega gas marketing contract that went into effect in October 2009 whereby the Company's gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Depreciation, Depletion, Amortization and Accretion - Oil and Gas. Depreciation, depletion and amortization expense decreased 33% to $15.9 million for the quarter ended June 30, 2010, as compared to $23.8 million for the comparable year earlier period. Depletion expense for the quarter ended June 30, 2010 decreased to $14.9 million from $23.1 million for the quarter ended June 30, 2009 due to lower production volumes and a decrease in the per unit depletion rate. The Company's depletion rate decreased from $4.66 per Mcfe for the quarter ended June 30, 2009 to $3.82 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties and Vega area proved undeveloped reserves added as a result of higher Piceance gas prices.
General and Administrative Expense. General and administrative expense increased 30% to $11.6 million for the quarter ended June 30, 2010, as compared to $9.0 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process and to increased non-cash stock compensation expense related to restricted stock granted in December 2009, partially offset by reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense.
RESULTS FOR THE SIX MONTHS ENDED JUNE 30, 2010
The Company reported a six month net loss attributable to common stockholders of ($162.5 million), or ($0.59) per share, compared with a net loss attributable to common stockholders of ($197.9 million), or ($1.35) per share, in the six months ended June 30, 2009. The net loss attributable to common stockholders for the six months ended June 30, 2010 includes a $96.1 million impairment charge associated with assets held for sale.
For the six months ended June 30, 2010, the Company reported production of 9.7 Bcfe. Approximately 2.7 Bcfe of production for the six month period was from assets sold in the Wapiti Transaction, of which 1.7 Bcfe is accounted for under "Discontinued Operations". The following discussion is on a "Continuing Operations" basis.
Total revenue decreased 1% to $75.4 million for the six months ended June 30, 2010, versus revenue of $76.2 million in the six months ended June 30, 2009. The decrease is primarily related to a $31.2 million gain associated with the offshore California litigation in 2009, offset by a $16.9 million period-over-period increase in oil and gas sales and a $14.1 million increase in contract drilling and trucking fees, due to improved third party rig utilization. For the six months ended June 30, 2010, oil and gas sales increased 44% to $55.0 million, as compared to $38.1 million for the prior year period. The increase was principally the result of a 102% increase in natural gas prices and a 68% increase in oil prices, partially offset by a 22% decrease in production. The average natural gas price received during a six months ended June 30, 2010 increased to $5.38 per Mcf compared to $2.66 per Mcf for the year earlier period. The average oil price received during the six months ended June 30, 2010 increased to $70.54 per Bbl compared to $41.99 per Bbl for the year earlier period.
SIX MONTHS ENDED PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2010 and 2009 are as follows:
Six Months Ended June 30, -------- 2010 2009 ---- ---- Production - Continuing Operations: Oil (Mbbl) 299 405 Gas (Mmcf) 6,299 7,934 Total Production (Mmcfe) - Continuing Operations 8,093 10,364 Average Price - Continuing Operations: Oil (per barrel) $70.54 $41.99 Gas (per Mcf) $5.38 $2.66 Costs (per Mcfe) - Continuing Operations: Lease operating expense $1.88 $1.42 Transportation expense $0.96 $0.45 Production taxes $0.35 $0.25 Depletion expense $3.67 $4.29 Realized derivative losses (per Mcfe) $0.58 $-
Lease Operating Expense. Lease operating expenses for the six months ended June 30, 2010 of $15.2 million was comparable to $14.7 million in the year earlier period. Lease operating expense per Mcfe for the six months ended June 30, 2010 increased to $1.88 per Mcfe from $1.42 per Mcfe for the comparable year earlier period. The increase on a per unit basis was primarily due to increased water handling costs in the Vega area and the effect of fixed costs spread over a 22% decline in production volumes.
Transportation Expense. Transportation expense for the six months ended June 30, 2010 increased to $7.8 million from $4.6 million in the prior year. Transportation expense per Mcfe for the six months ended June 30, 2010 increased to $0.96 per Mcfe from $0.45 per Mcfe. The increase on a per unit basis is primarily the result of changes to the Company's Vega gas marketing contract that went into effect in October 2009 whereby the Company's gas is processed through a higher efficiency plant. The Vega gas marketing contract has resulted in higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.
Depreciation, Depletion, Amortization and Accretion - Oil and Gas. Depreciation, depletion and amortization expense decreased 32% to $31.3 million for the six months ended June 30, 2010, as compared to $45.9 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2010 was $29.7 million compared to $44.4 million for the six months ended June 30, 2009. The depletion rate decreased from $4.29 per Mcfe for the six months ended June 30, 2009 to $3.67 per Mcfe for the current year period primarily due to the effect of impairments recorded during late 2009 on high depletion rate properties and Vega area proved undeveloped reserves added as a result of higher Piceance gas prices.
General and Administrative Expense. General and administrative expense increased 7% to $23.0 million for the six months ended June 30, 2010, as compared to $21.6 million for the comparable prior year period. The increase in general and administrative expenses is attributed to costs associated with the strategic alternatives evaluation process and to increased non-cash stock compensation expense related to restricted stock granted in December 2009, partially offset by reduced staffing as a result of reductions in force during the first half of 2009 resulting in lower cash compensation expense.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the Company's open derivative contracts at June 30, 2010:
Remaining Fixed Commodity Volume Price Term Index Price --------- ------ ----- ---- ----------- 1,000 Bbls / July '10 -Dec Crude oil Day(1) $52.25 '10 NYMEX - WTI Jan '11 -Dec Crude oil 500 Bbls / Day $57.70 '11 NYMEX - WTI Natural 6,000 MMBtu / July '10 -Dec gas Day $5.720 '10 NYMEX - HHUB Natural 15,000 MMBtu / July '10 -Dec gas Day $4.105 '10 CIG Natural 5,367 MMBtu / July '10 -Dec gas Day $3.973 '10 CIG Natural 12,000 MMBtu / Jan '11 -Dec gas Day $5.150 '11 CIG Natural 3,253 MMBtu / Jan '11 -Dec gas Day $5.040 '11 CIG (1) As a result of the closing of the Wapiti Transaction, for the period from August to December 2010, the Company expects its oil derivative contracts to equal 108% to 114% of forecast oil and condensate production sold on WTI based terms. Because derivative contract volumes are anticipated to exceed physical production volumes in certain months, the Company could be exposed to financial derivative losses in excess of oil revenue gains to the extent WTI oil prices rise from current levels.
The pre-credit risk adjusted fair value of the Company's net derivative liabilities as of June 30, 2010 was $6.6 million. A credit risk adjustment of $0.6 million to the fair value of the derivatives reduced the reported amount of the net derivative liabilities to $6.0 million.
OPERATIONS UPDATE
Total Company net production for the month of August is expected to be 34 Mmcfe/d. During the second quarter 2010 the Company completed one well from its drilled and uncompleted inventory in the Vega area. The Company expects to complete the remaining 15 drilled and uncompleted wells in the third and fourth quarters of this year, utilizing its redesigned completion techniques.
2010 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE
With the completion of the Wapiti Transaction and the reduction in the Company's credit facility borrowing base to $35.0 million, capital expenditure limitations in the Company's credit agreement for the third and fourth quarters of 2010 are set at $18.0 million and $10.0 million, respectively. The Company intends to focus capital expenditures for the remainder of the year on completing 15 previously drilled wells in the Vega area. Based on this level of development and considering production sold in the Wapiti Transaction, the Company expects oil and gas equivalent production for the remainder of the year to range between 6.9 Bcfe and 7.2 Bcfe.
INVESTOR CONFERENCE CALL
The Company will host an investor conference call Tuesday, August 10, 2010 at 12:00 noon Eastern Time (10:00 am Mountain Time) to discuss financial and operating results for the second quarter 2010.
Shareholders and other interested parties may participate in the conference call by dialing 877-317-6789 (international callers dial 412-317-6789) and referencing the ID code "Delta Petroleum call," a few minutes before 12:00 noon Eastern Time on August 10, 2010. 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 one hour after the completion of the conference call from August 10, 2010 until August 19, 2010 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 443139.
ABOUT DELTA PETROLEUM CORPORATION
Delta Petroleum Corporation is an oil and gas exploration and development company based in Denver, Colorado. The Company's core area of operation is the Rocky Mountain Region, where the majority of its proved reserves, production and long-term growth prospects are located. 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. 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 the effects of oil and natural gas prices, availability of capital to fund required payments on our credit facility and our projected capital development and working capital needs, the ability to obtain necessary third party consents to transfer assets to be conveyed in the Wapiti Transaction, as well as general market conditions, competition and pricing, the increase in supply and contraction in demand for natural gas in the United States, lack of availability of third party services including frac crews, the impact of current economic and financial conditions on our ability to raise capital, availability of borrowings under our credit facility and the ability to obtain a new or replacement credit facility, 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 on Form 10-K for the year ended December 31, 2009 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 at investorrelations@deltapetro.com
DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) ----------- June 30, December 31, 2010 2009 ---- ---- (In thousands, except ASSETS share data) Current assets: Cash and cash equivalents $11,051 $61,918 Short-term restricted deposits 100,000 100,000 Trade accounts receivable, net of allowance for doubtful accounts of $100 and $100, respectively 17,757 16,654 Oil and gas properties held for sale 99,902 - Deposits and prepaid assets 2,051 3,103 Inventories 4,150 5,588 Other current assets 3,169 5,189 ----- ----- Total current assets 238,080 192,452 Property and equipment: Oil and gas properties, successful efforts method of accounting: Unproved 236,096 280,844 Proved 944,163 1,379,920 Drilling and trucking equipment 175,844 177,762 Pipeline and gathering systems 96,446 92,064 Other 15,681 16,154 ------ ------ Total property and equipment 1,468,230 1,946,744 Less accumulated depreciation and depletion (578,771) (800,501) -------- -------- Net property and equipment 889,459 1,146,243 ------- --------- Long-term assets: Long-term restricted deposit 100,000 100,000 Investments in unconsolidated affiliates 4,928 7,444 Deferred financing costs 2,442 3,017 Other long-term assets 6,163 8,329 ----- ----- Total long-term assets 113,533 118,790 ------- ------- Total assets $1,241,072 $1,457,485 ========== ========== LIABILITIES AND EQUITY Current liabilities: Credit facility - Delta $119,538 $- Credit facility - DHS 73,590 83,268 Installments payable on property acquisition 99,144 97,874 Accounts payable 31,175 44,225 Liabilities related to oil and gas properties held for sale 7,280 - Offshore litigation payable - 13,877 Other accrued liabilities 11,628 13,459 Derivative instruments 4,705 19,497 ----- ------ Total current liabilities 347,060 272,200 Long-term liabilities: Installments payable on property acquisition, net of current portion 96,619 95,381 7% Senior notes 149,647 149,609 3 3/4% Senior convertible notes 106,268 104,008 Credit facility - Delta - 124,038 Asset retirement obligations 4,620 7,654 Derivative instruments 1,319 7,475 ----- ----- Total long-term liabilities 358,473 488,165 Commitments and contingencies Equity: Preferred stock, $.01 par value: authorized 3,000,000 shares, none issued - - Common stock, $.01 par value: authorized 600,000,000 shares, issued 282,760,000 shares at June 30, 2010 and 282,548,000 shares at December 31, 2009 2,828 2,825 Additional paid-in capital 1,631,517 1,625,035 Treasury stock at cost; 34,000 shares at June 30, 2010 and 42,000 shares at December 31, 2009 (75) (268) Accumulated deficit (1,101,557) (939,010) ---------- -------- Total Delta stockholders' equity 532,713 688,582 ------- ------- Non-controlling interest 2,826 8,538 ----- ----- Total equity 535,539 697,120 ------- ------- Total liabilities and equity $1,241,072 $1,457,485 ========== ========== DELTA PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) Three Months Ended June 30, -------- 2010 2009 ---- ---- (In thousands, except per share amounts) Revenue: Oil and gas sales $25,067 $19,267 Contract drilling and trucking fees 11,064 1,674 Gain (loss) on offshore litigation award and property sales, net (109) (81) ---- --- Total revenue 36,022 20,860 ------ ------ Operating expenses: Lease operating expense 8,015 6,845 Transportation expense 4,454 2,178 Production taxes 1,377 1,061 Exploration expense 358 471 Dry hole costs and impairments 30,767 106,621 Depreciation, depletion, amortization and accretion - oil and gas 15,920 23,846 Drilling and trucking operating expenses 8,123 2,342 Depreciation and amortization - drilling and trucking 5,226 6,175 General and administrative 11,640 8,966 Executive severance expense, net - 3,739 --- ----- Total operating expenses 85,880 162,244 ------ ------- Operating loss (49,858) (141,384) ------- -------- Other income and (expense): Interest expense and financing costs, net (9,556) (15,775) Other income (expense), net (299) 1,256 Realized loss on derivative instruments, net (601) - Unrealized gain (loss) on derivative instruments, net 3,676 (15,647) Income (loss) from unconsolidated affiliates 991 (3,617) --- ------ Total other expense (5,789) (33,783) ------ ------- Loss from continuing operations before income taxes and discontinued operations (55,647) (175,167) Income tax expense (benefit) 203 265 --- --- Loss from continuing operations (55,850) (175,432) Discontinued operations: Loss from discontinued operations, net of tax (96,630) (5,051) ------- ------ Net loss (152,480) (180,483) Less net loss attributable to non-controlling interest 2,730 8,165 ----- ----- Net loss attributable to Delta common stockholders $(149,750) $(172,318) ========= ========= Amounts attributable to Delta common stockholders: Loss from continuing operations $(53,120) $(167,267) Loss from discontinued operations, net of tax (96,630) (5,051) ------- ------ Net loss $(149,750) $(172,318) --------- --------- Basic income (loss) attributable to Delta common stockholders per common share: Loss from continuing operations $(0.19) $(0.86) Discontinued operations (0.35) (0.03) ----- ----- Net loss $(0.54) $(0.89) ------ ------ Diluted income (loss) attributable to Delta common stockholders per common share: Loss from continuing operations $(0.19) $(0.86) Discontinued operations (0.35) (0.03) ----- ----- Net loss $(0.54) $(0.89) ------ ------ Weighted average common shares outstanding: Basic 275,832 193,028 Diluted 275,832 193,028 Six Months Ended June 30, -------- 2010 2009 ---- ---- (In thousands, except per share amounts) Revenue: Oil and gas sales $54,970 $38,116 Contract drilling and trucking fees 20,996 6,887 Gain (loss) on offshore litigation award and property sales, net (538) 31,204 ---- ------ Total revenue 75,428 76,207 ------ ------ Operating expenses: Lease operating expense 15,202 14,749 Transportation expense 7,807 4,626 Production taxes 2,821 2,550 Exploration expense 584 1,531 Dry hole costs and impairments 31,121 108,064 Depreciation, depletion, amortization and accretion - oil and gas 31,339 45,850 Drilling and trucking operating expenses 16,012 7,598 Depreciation and amortization - drilling and trucking 10,798 11,967 General and administrative 23,027 21,594 Executive severance expense, net - 3,739 --- ----- Total operating expenses 138,711 222,268 ------- ------- Operating loss (63,283) (146,061) ------- -------- Other income and (expense): Interest expense and financing costs, net (20,116) (32,201) Other income (expense), net (170) 1,408 Realized loss on derivative instruments, net (4,714) - Unrealized gain (loss) on derivative instruments, net 20,948 (21,111) Income (loss) from unconsolidated affiliates 983 (2,870) --- ------ Total other expense (3,069) (54,774) ------ ------- Loss from continuing operations before income taxes and discontinued operations (66,352) (200,835) Income tax expense (benefit) 478 (318) --- ---- Loss from continuing operations (66,830) (200,517) Discontinued operations: Loss from discontinued operations, net of tax (101,642) (9,400) -------- ------ Net loss (168,472) (209,917) Less net loss attributable to non-controlling interest 5,925 12,046 ----- ------ Net loss attributable to Delta common stockholders $(162,547) $(197,871) ========= ========= Amounts attributable to Delta common stockholders: Loss from continuing operations $(60,905) $(188,471) Loss from discontinued operations, net of tax (101,642) (9,400) -------- ------ Net loss $(162,547) $(197,871) --------- --------- Basic income (loss) attributable to Delta common stockholders per common share: Loss from continuing operations $(0.22) $(1.29) Discontinued operations (0.37) (0.06) ----- ----- Net loss $(0.59) $(1.35) ------ ------ Diluted income (loss) attributable to Delta common stockholders per common share: Loss from continuing operations $(0.22) $(1.29) Discontinued operations (0.37) (0.06) ----- ----- Net loss $(0.59) $(1.35) ------ ------ Weighted average common shares outstanding: Basic 275,652 146,248 Diluted 275,652 146,248 DELTA PETROLEUM CORPORATION AND SUBSIDIARIES RECONCILIATION OF NON-GAAP MEASURES (Unaudited) ($in thousands) --------------- June THREE MONTHS ENDED June 30, 30, 2010 2009 ---- ---- CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES $(6,332) $38,757 Changes in assets and liabilities 6,650 (3,778) Less net proceeds from offshore litigation award - (48,701) Exploration costs 358 471 --- --- Discretionary cash flow (deficiency)* $676 $(13,251) ==== ======== June SIX MONTHS ENDED June 30, 30, 2010 2009 ---- ---- CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES $(23,273) $32,849 Changes in assets and liabilities 27,271 (11,286) Less net proceeds from offshore litigation award - (48,701) Exploration costs 584 1,531 --- ----- Discretionary cash flow (deficiency)* $4,582 $(25,607) ====== ======== * Discretionary cash flow represents net cash provided by (used in) operating activities before changes in assets and liabilities, net proceeds from offshore litigation award and 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. THREE MONTHS ENDED June 30, June 30, 2010 2009 ---- ---- Net loss $(152,480) $(180,483) Minority interest 2,730 8,165 Income tax expense 203 265 Interest expense and financing costs, net 9,556 15,775 Depletion, depreciation and amortization 26,973 36,107 (Gain) loss on offshore litigation award, property sales and other 440 (1,643) Unrealized (gain) loss on derivative instruments, net (3,676) 15,647 Exploration, dry hole and impairment costs 123,287 107,092 ------- ------- EBITDAX** $7,033 $925 ====== ==== THREE MONTHS ENDED June 30, June 30, 2010 2009 ---- ---- CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES $(6,332) $38,757 Changes in assets and liabilities 6,650 (3,778) Less net proceeds from offshore litigation award - (48,701) Interest net of financing costs 6,141 10,446 Exploration costs 358 471 Other non-cash items 216 3,730 --- ----- EBITDAX** $7,033 $925 ====== ==== SIX MONTHS ENDED June 30, June 30, 2010 2009 ---- ---- Net loss $(168,472) $(209,917) Minority interest 5,925 12,046 Income tax expense (benefit) 478 (318) Interest expense and financing costs, net 20,116 32,201 Depletion, depreciation and amortization 55,731 68,721 (Gain) loss on offshore litigation award, property sales and other 801 (32,928) Unrealized (gain) loss on derivative instruments, net (20,948) 21,111 Exploration, dry hole and impairment costs 123,867 109,595 ------- ------- EBITDAX** $17,498 $511 ======= ==== SIX MONTHS ENDED June 30, June 30, 2010 2009 ---- ---- CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES $(23,273) $32,849 Changes in assets and liabilities 27,271 (11,286) Less net proceeds from offshore litigation award - (48,701) Interest net of financing costs 12,901 20,774 Exploration costs 584 1,531 Other non-cash items 15 5,344 --- ----- EBITDAX** $17,498 $511 ======= ==== ** EBITDAX represents net loss before minority interest, income tax expense (benefit), interest expense and financing costs, net, depreciation, depletion and amortization expense, gain and loss on sale of oil and gas properties, offshore litigation and other investments, net unrealized gains and losses 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. THREE MONTHS ENDED June 30, 2010 ------------- Oil Gas (Mbbl) (Mmcf) Mmcfe ------- ------- ----- Total Production 153 3,777 4,697 Less Wapiti Transaction production reported in discontinued operations*** (4) (773) (795) --- ---- ---- Production from Continuing Operations 150 3,004 3,902 Less Wapiti Transaction production reported in continuing operations*** (54) (223) (547) --- ---- ---- Production from Remaining Operations 96 2,781 3,355 === ===== ===== THREE MONTHS ENDED June 30, 2009 ------------- Oil Gas (Mbbl) (Mmcf) Mmcfe ------- ------- ----- Total Production 202 4,483 5,695 Less Wapiti Transaction production reported in discontinued operations*** (4) (707) (731) --- ---- ---- Production from Continuing Operations 198 3,776 4,964 Less Wapiti Transaction production reported in continuing operations*** (71) (316) (742) --- ---- ---- Production from Remaining Operations 127 3,460 4,222 === ===== ===== SIX MONTHS ENDED June 30, 2010 Oil Gas (Mbbl) (Mmcf) Mmcfe ------- ------- ----- Total Production 309 7,889 9,743 Less Wapiti Transaction production reported in discontinued operations*** (10) (1,590) (1,650) --- ------ ------ Production from Continuing Operations 299 6,299 8,093 Less Wapiti Transaction production reported in continuing operations*** (106) (443) (1,079) ---- ---- ------ Production from Remaining Operations 193 5,856 7,014 === ===== ===== SIX MONTHS ENDED June 30, 2009 Oil Gas (Mbbl) (Mmcf) Mmcfe ------- ------- ----- Total Production 414 9,532 12,016 Less Wapiti Transaction production reported in discontinued operations*** (9) (1,598) (1,652) --- ------ ------ Production from Continuing Operations 405 7,934 10,364 Less Wapiti Transaction production reported in continuing operations*** (147) (627) (1,509) ---- ---- ------ Production from Remaining Operations 258 7,307 8,855 === ===== ===== *** The properties included in the Wapiti Transaction were comprised of non-operated properties in which Delta sold all of its interest to Wapiti and operated properties in which Delta sold half of its interest to Wapiti. In accordance with applicable accounting rules, properties in which Delta sold all of its interest are reported as discontinued operations. However, properties in which Delta only sold half of its interest to Wapiti are required to be reported as a component of continuing operations. As a result, the Company's results from continuing operations for all periods presented include production from properties included in the Wapiti Transaction in which Delta now owns 50% less than the amounts included in the Company's financial statements as continuing operations. As a result, the Company believes that the information presented will be useful to investors and analysts in understanding the impact of the transaction upon the Company's production. Adjustments "from Continuing Operations" and totals "from Remaining Operations" are non-GAAP measures, but are reconciled to their equivalent GAAP measure.
Delta Petroleum Corporation
CONTACT: Delta Petroleum Corporation, +1-303-293-9133,
investorrelations@deltapetro.com
Web Site: http://www.deltapetro.com/
