DELTA PETROLEUM CORP. 
By DENVER, Aug. 6 /PRNewswire-FirstCall/ -- Delta Petroleum Corporation (Nasdaq: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the second quarter of 2009.
Dan Taylor, the Company's Chairman stated, "The financial and operational results of Delta for the second quarter reflect the continued challenging natural gas price environment, reduction of our capital outflows, and significant cost savings efforts. We have taken very important measures that have improved our liquidity position during the quarter. We are pleased that the Company was able to complete a common equity offering that provided net proceeds of $247.2 million to reduce our debt balance and improve our working capital position. Additionally, the board of directors and I have reviewed an extensive liquidity analysis and have approved measures to preserve liquidity under varying commodity price environments. With these measures, and with an improved cost structure and lower overhead, we are in a much more secure liquidity position. We are convinced that these efforts will translate into improved financial performance and greater flexibility in the latter half of 2009 and thereafter."
John Wallace, Delta's President and Chief Operating Officer stated, "During the second quarter we began to experience improved operating metrics resulting from our cost cutting initiatives. We reduced our work force by approximately 20% in the quarter, which was in addition to the one-third reduction that happened in the first quarter. Other general and administrative expenses have been reduced and should continue to decline during the remainder of the year. Operationally, we have temporarily suspended our completion activities in the Piceance Basin. We have 23 wells that have been drilled, but remain uncompleted. This decision was made based upon the current Rocky Mountain gas price environment, and our desire to preserve capital. While this will clearly affect our production for the year, we believe it is the prudent measure to take at this point. We remain confident in the long-term value of our assets in the Piceance and will reinitiate drilling and completion activities when market conditions improve."
"On the Gray 31-23 well in the Columbia River Basin we have reached total depth and are undergoing completion operations. As stated previously, the Company has encountered and logged numerous highly porous and permeable gas-charged sands during the drilling of the well. We anticipate having completion results from the entire well and will comment on them once the well has been fully completed."
LIQUIDITY AND OUTLOOK
On May 13, 2009, Delta completed an underwritten public offering of 172.5 million shares of common stock at $1.50 per share for net proceeds of $247.2 million. On May 19, 2009, the Company received $48.7 million of net proceeds related to the first portion of the judgments awarded on the offshore litigation with the U.S. government. With proceeds from these transactions, the Company has reduced borrowings outstanding under the credit facility from $294.5 million at December 31, 2008 to $83.0 million at June 30, 2009, with $140.8 million of remaining availability based on the current $225.0 million borrowing base. Delta continues to have the support of its banking group and is confident that the September bank re-determination will not have a material impact on the Company's effort to preserve liquidity. In addition, Delta reduced its accounts payable from $159.0 million at December 31, 2008 to $79.0 million at June 30, 2009.
During May 2009, DHS sold Rig #7 for cash proceeds of $7.8 million which, combined with proceeds from minor spare equipment sales and the collection of accounts receivable, were used to reduce borrowings outstanding under the DHS credit facility from $93.8 million at December 31, 2008 to $83.3 million at June 30, 2009. DHS remains out of compliance with the debt covenants under its credit facility and its previous forbearance agreement has expired. DHS is at risk of losing their assets if they are not able to successfully negotiate a new credit agreement with Lehman Commercial Paper Inc.
During the six months ended June 30, 2009, the Company had an operating loss of $155.5 million (or $78.6 million exclusive of dry holes and impairments and gain on offshore litigation settlement), net cash provided by operating activities of $32.8 million and net cash provided by financing activities of $22.7 million.
RESULTS FOR THE SECOND QUARTER
For the quarter ended June 30, 2009, the Company reported production of 5.69 billion cubic feet equivalents (Bcfe), a decrease of 8% when compared with the second quarter of 2008 and a decrease of 10% when compared with the first quarter of 2009. Total revenue decreased 72% to $22.9 million in the quarter, versus revenue of $81.1 million in the quarter ended June 30, 2008. Revenue from oil and gas sales declined 71% to $21.3 million, compared with $73.2 million in the prior year quarter. The decrease was primarily due to a 75% reduction in average realized gas prices and a 54% decrease in average realized oil prices, as well as an 8% decrease in total production. Given a substantially different market environment from 2008 to 2009, it is important to note that revenue from oil and gas sales declined 4% to $21.3 million, compared with $22.2 million in the first quarter of 2009. The decrease was primarily due to a 23% reduction in average realized gas prices and 10% decrease in production offset by a 69% increase in the average oil price. Revenue from contract drilling and trucking fees decreased 79% to $1.7 million in the current quarter, versus $7.9 million in the second quarter of 2008 and decreased 68% in comparison to the first quarter of 2009. The decreases were due to lower third party rig utilization in the three months ended June 30, 2009, resulting from a significant industry slowdown driven by lower commodity prices.
The Company reported a second quarter net loss attributable to Delta common stockholders of ($172.3 million), or ($0.89) per share, compared with a net loss attributable to Delta common stockholders of ($23.4 million), or ($0.23) per share, in the second quarter of 2008. The increased loss was primarily due to impairments recorded in the second quarter of 2009 and significantly lower natural gas and oil prices compared to the same period prior year.
SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per thousand cubic feet equivalent (Mcfe) for the three months ended June 30, 2009 and 2008 are as follows:
Three Months Ended
June 30,
2009 2008
Production - Continuing Operations:
Oil (Mbbl) 202 247
Gas (Mmcf) 4,483 4,674
Total Production (Mmcfe) 5,692 6,156
Average Price - Continuing Operations:
Oil (per barrel) $53.18 $115.05
Gas (per Mcf) $2.37 $9.59
Costs per Mcfe - Continuing Operations:
Lease operating expense $1.34 $1.45
Production taxes $0.18 $0.69
Transportation costs $0.44 $0.40
Depletion expense $5.13 $3.93
Realized derivative losses $- $(1.16)
Lease operating expense. Lease operating expense for the quarter ended June 30, 2009 decreased to $7.6 million from $9.0 million in the year earlier period primarily due to lower production and lower costs in Howard Ranch and Newton. Lease operating expense from continuing operations per Mcfe for the three months ended June 30, 2009 decreased to $1.34 per Mcfe from $1.45 per Mcfe for the comparable year earlier period.
Depreciation, depletion and amortization expense. Oil and gas depreciation, depletion and amortization expense increased 21% to $29.9 million for the three months ended June 30, 2009, as compared to $24.8 million for the same period prior year. Depletion expense for the three months ended June 30, 2009 was $29.2 million compared to $24.2 million for the three months ended June 30, 2008. The depletion rate increased from $3.93 per Mcfe for the three months ended June 30, 2008 to $5.13 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at June 30, 2009 on the reserves used in the Company's depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.
Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of approximately $106.6 million for the three months ended June 30, 2009 compared to $430,000 for the comparable period a year ago. During the three months ended June 30, 2009, dry hole and impairment costs primarily related to unproved leasehold impairments in Garden Gulch ($38.6 million), Haynesville ($26.7 million), and Lighthouse ($14.7 million); a $10.5 million impairment of Vega area surface acres, $6.5 million of DHS equipment and rig impairments, $4.3 million of tubular inventory impairments and a $1.9 million impairment of the Paradox pipeline. The majority of the impairments were made to the unproved properties, inventory and spare drilling equipment and no proved producing oil and gas properties were impaired. These impairments were driven by sustained lower commodity prices, reduced lease rates and delayed development activities.
General and Administrative Expense. General and administrative expense decreased 35% to $9.0 million for the three months ended June 30, 2009, as compared to $13.8 million for the same period prior year. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications related to reductions in force in March and June 2009 affecting approximately fifty percent of personnel. As a result of the reduction in force during the three months ended June 30, 2009, further reductions in cash general and administrative costs are expected in future periods.
RESULTS FOR THE SIX MONTHS
For the six months ended June 30, 2009, the Company reported production of 12.0 Bcfe, an increase of 4% when compared with the six months ended June 30, 2008. Total revenue decreased 44% to $81.6 million in the six months ended June 30, 2009, versus revenue of $145.6 million in the six months ended June 30, 2008. Revenue from oil and gas sales declined 66% to $43.5 million, compared with $127.0 million in the prior year period. The decrease was primarily the result of a 59% decrease in oil prices and a 69% decrease in natural gas prices, slightly offset by a 4% increase in production. The average oil price received during the six months ended June 30, 2009 decreased to $42.03 per Bbl compared to $102.62 per Bbl for the year earlier period. The average natural gas price received during the six months ended June 30, 2009 decreased to $2.74 per Mcf compared to $8.80 per Mcf for the year earlier period. Revenue from contract drilling and trucking fees decreased to $6.9 million compared to $18.6 million for the same period in the prior year. The decrease is the result of lower third party rig utilization during the six months ended June 30, 2009 compared to the same period prior year, resulting from a significant industry slowdown driven by lower commodity prices.
The Company reported a six month net loss attributable to common stockholders of ($197.9 million), or ($1.35) per share, compared with a net loss attributable to common stockholders of ($44.2 million), or ($0.49) per share, for the six months ended June 30, 2008. The increased loss was due to impairments recorded in the second quarter of 2009 coupled with lower oil and natural gas prices offset by an offshore litigation gain recorded in 2009 and lower derivative losses in 2009.
SIX MONTHS PRODUCTION VOLUMES, UNIT PRICES AND COSTS
Production volumes, average prices received and cost per equivalent Mcf for the six months ended June 30, 2009 and 2008 are as follows:
Six Months Ended
June 30,
2009 2008
Production - Continuing Operations:
Oil (Mbbl) 414 513
Gas (Mmcf) 9,532 8,442
Total Production (Mmcfe) 12,017 11,522
Average Price - Continuing Operations:
Oil (per barrel) $42.03 $102.62
Gas (per Mcf) $2.74 $8.80
Costs per Mcfe - Continuing Operations:
Lease operating expense $1.45 $1.48
Production taxes $0.22 $0.68
Transportation costs $0.48 $0.37
Depletion expense $4.60 $4.05
Realized derivative losses $- $(0.76)
Lease operating expense. Lease operating expenses for the six months ended June 30, 2009 of $17.4 million was comparable to $17.0 million in the year earlier period as both production and per unit cost rates remained consistent. Lease operating expense from continuing operations per Mcfe for the six months ended June 30, 2009 decreased to $1.45 per Mcfe from $1.48 per Mcfe for the comparable year earlier period.
Depreciation, depletion and amortization expense. Oil and gas depreciation, depletion and amortization expense increased 19% to $56.8 million for the six months ended June 30, 2009, as compared to $47.8 million for the comparable year earlier period. Depletion expense for the six months ended June 30, 2009 was $55.3 million compared to $46.7 million for the six months ended June 30, 2008. The depletion rate increased from $4.05 per Mcfe for the six months ended June 30, 2008 to $4.60 per Mcfe for the current year period primarily due to the effect of low spot commodity prices at June 30, 2009 on the reserves used in the Company's depletion calculation, offset by the effect of impairments recorded in the fourth quarter of 2008.
Dry Hole Costs and Impairments. Delta incurred dry hole and impairment costs of approximately $108.1 million for the six months ended June 30, 2009 compared to $2.8 million for the comparable period a year ago. During the six months ended June 30, 2009, dry hole and impairment costs primarily related to unproved leasehold impairments in Garden Gulch ($38.6 million), Haynesville ($26.7 million), and Lighthouse ($14.7 million); a $10.5 million impairment of Vega area surface acres, $6.5 million of DHS equipment and rig impairments, $4.3 million of tubular inventory impairments, and a $1.9 million impairment of the Paradox pipeline.
General and Administrative Expense. General and administrative expense decreased 21% to $21.6 million for the six months ended June 30, 2009, as compared to $27.2 million for the comparable prior year period. The decrease in general and administrative expenses is primarily attributed to a decrease in non-cash stock compensation expense from lower executive performance share costs, and also from forfeitures and modifications related to reductions in force in March and June 2009 affecting approximately fifty percent of the Company's personnel. As a result of the reductions in force during the six months ended June 30, 2009, reductions in cash general and administrative costs are expected in future periods.
ADDITIONAL FINANCIAL INFORMATION
The following table summarizes the open derivative contracts at June 30, 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 $21.1 million at June 30, 2009.
OPERATIONS UPDATE
Columbia River Basin, WA, 50% WI - The Gray 31-23 well reached total depth and completion operations have commenced on the side-track wellbore. The liner in the original wellbore failed during cementing operations. The Company is targeting an over-pressured gas charged section of sand and completion procedures over the next few months will be focused on these intervals.
If the flow rates and pressure testing are favorable and indicate commercial development, the Company intends to drill a confirmation well targeting these sands, which is projected to take approximately five months to drill. If these results do not support a standalone well in the targeted sands, then the Company will consider drilling a Roslyn well that would be designed to commingle or ultimately produce from both intervals. A Roslyn well is projected to take six months to drill. The Roslyn formation is considered by the Company to be more prospective than it was prior to drilling the Gray 31-23 because of the presence of the over-pressuring and higher than expected gas column.
Future wells should cost less due to experience gained and procedural improvements. Preliminary pipeline scoping work is being conducted to mitigate time sensitive permitting issues. Furthermore, the Company is permitting additional wells on the Bronco Prospect.
Piceance Basin, CO, 31% - 100% WI - The Company has continued to suspend drilling operations in the Vega Area due to gas price. During the second quarter the Company continued minimal completion activity on wells that were drilled in prior quarters, completing a total of eight wells out of the total 31 wells that have been drilled but not yet completed. The inventory of drilled, but uncompleted wells stands at 23. Although the Company has experienced reductions in completion costs of approximately 40% in 2009, the decision has been made to temporarily suspend all well completion activity as the deployment of the completion capital does not currently meet the Company's investment return threshold, and to preserve capital in the current environment. If completion costs continue to decline or natural gas prices in the Rocky Mountain region rise to more attractive levels the decision to complete the well inventory will be re-evaluated. Because the field is currently designed for increased drilling activity and natural gas transportation, production volume would quickly grow once drilling and completion activity resumes. Current production from the Piceance Basin approximates 36.5 million cubic feet equivalent per day (Mmcfe/d) net. During the suspension of completion efforts in the Vega Area, the current production in the field will experience its naturally-occurring decline.
The Company is continuing with the permitting process for a new water treatment facility that is anticipated to reduce water hauling and disposal costs over the long term development of the field. The new water treatment facility is a patented distillation process that will allow the Company to surface discharge its treated water, thereby reducing the water hauling costs in the field, which have been one of the highest operating costs.
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 undeveloped areas and the Company has begun the sales process of select non-producing assets.
CALIFORNIA OFFSHORE LITIGATION
The Company has been awarded damages from the United States government in two separate judgments rendered at different times in the gross 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 government paid $60.0 million of the first judgment during the quarter, which provided the Company with $48.7 million, after payment of overrides and other participating interests. The second judgment in the amount of $91.4 million (approximately $68 million net) 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 has suspended its completion activities in the Piceance Basin and therefore the production in the basin is expected to decline. The decision to suspend completion activities is primarily due to the desire to preserve liquidity and reschedule the expenditures to yield a better return on investment. Accordingly, production guidance for 2009 has been revised to total 21 Bcfe for the year. Drilling and completion related capital expenditure guidance for the year is currently expected to be approximately $60 million, a revision upward from the previous guidance of $52 million. The increase in the capital expenditure guidance is due to the unexpected duration of drilling and completion activities in the Columbia River Basin, and the now planned drilling of the next well in the basin, the Gray 25-33. Additionally, much of the capital previously dedicated to the completion of the drilled well inventory in the Piceance Basin will be redeployed to the Columbia River Basin for completion, permitting and right-of-way procurement activities.
INVESTOR CONFERENCE CALL
An investor conference call has been scheduled for 12:00 noon Eastern Time on Thursday, August 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 reference the ID code "Delta Petroleum call," a few minutes before 12:00 noon Eastern Time on August 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 one hour after the completion of the conference call from August 6, 2009 until August 14, 2009 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 432413#.
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 on Form 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
at info@deltapetro.com
or
RJ Falkner & Company, Inc., Investor Relations Counsel, at (800) 377-9893
or via email at info@rjfalkner.com
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2009 2008
ASSETS (In thousands, except share data)
Current assets:
Cash and cash equivalents $5,744 $65,475
Short-term restricted deposits 102,888 100,000
Trade accounts receivable, net of
allowance for doubtful accounts of $631
and $652, respectively 13,569 30,437
Deposits and prepaid assets 3,717 11,253
Inventories 8,406 9,140
Deferred tax assets - 231
Other current assets 6,729 6,221
Total current assets 141,053 222,757
Property and equipment:
Oil and gas properties, successful efforts
method of accounting:
Unproved 313,513 415,573
Proved 1,406,953 1,365,440
Drilling and trucking equipment 182,193 194,223
Pipeline and gathering systems 96,656 86,076
Other 16,048 29,107
Total property and equipment 2,015,363 2,090,419
Less accumulated depreciation and
depletion (729,184) (658,279)
Net property and equipment 1,286,179 1,432,140
Long-term assets:
Long-term restricted deposit 200,000 200,000
Marketable securities 1,977 1,977
Investments in unconsolidated affiliates 14,486 17,989
Deferred financing costs 4,242 7,640
Other long-term assets 14,587 12,460
Total long-term assets 235,292 240,066
Total assets $1,662,524 $1,894,963
LIABILITIES AND EQUITY
Current liabilities:
Credit facility - Delta $83,038 $294,475
Credit facility - DHS 83,268 -
Installments payable on property
acquisition 98,719 97,453
Accounts payable 79,035 159,024
Executive severance payable 2,888 -
Other accrued liabilities 12,190 13,576
Derivative instruments 7,434 -
Total current liabilities 366,572 564,528
Long-term liabilities:
Installments payable on property
acquisition, net of current portion 190,779 188,334
7% Senior notes 149,572 149,534
3 3/4% Senior convertible notes 101,780 99,616
Credit facility - DHS - 93,848
Asset retirement obligations 8,066 6,585
Derivative instruments 13,677 -
Deferred tax liabilities - 1,024
Total long-term liabilities 463,874 538,941
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 276,802,000
shares at June 30, 2009 and 103,424,000
shares at December 31, 2008 2,768 1,034
Additional paid-in capital 1,620,650 1,372,123
Treasury stock at cost; 1,036,000 shares
at June 30, 2009 and 36,000 shares at
December 31, 2008 (2,140) (540)
Executive severance payable in common
stock 1,700 -
Accumulated deficit (808,098) (610,227)
Total Delta stockholders' equity 814,880 762,390
Non-controlling interest 17,198 29,104
Total equity 832,078 791,494
Total liabilities and equity $1,662,524 $1,894,963
DELTA PETROLEUM CORPORATION
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2009 2008 2009 2008
(In thousands, except per share amounts)
Revenue:
Oil and gas sales $21,349 $73,232 $43,507 $126,992
Contract drilling and
trucking fees 1,674 7,875 6,887 18,595
Gain (loss) on offshore
litigation award (81) - 31,204 -
Total revenue 22,942 81,107 81,598 145,587
Operating expenses:
Lease operating expense 7,601 8,952 17,447 17,043
Transportation expense 2,505 2,449 5,760 4,272
Production taxes 1,025 4,263 2,605 7,804
Exploration expense 471 1,933 1,531 2,935
Dry hole costs and
impairments 106,621 430 108,064 2,769
Depreciation, depletion,
amortization and
accretion - oil and gas 29,932 24,752 56,754 47,791
Drilling and trucking operating
expenses 2,342 5,529 7,598 12,352
Depreciation and
amortization - drilling
and trucking 6,175 3,208 11,967 6,851
General and administrative
expense 8,966 13,826 21,594 27,247
Executive severance expense,
net 3,739 - 3,739 -
Total operating expenses 169,377 65,342 237,059 129,064
Operating income (loss) (146,435) 15,765 (155,461) 16,523
Other income and (expense):
Interest expense and financing
costs (15,883) (9,676) (32,957) (18,613)
Interest income 108 3,388 756 5,258
Other income (expense) 1,256 (185) 1,408 272
Realized loss on derivative
instruments, net - (7,130) - (8,765)
Unrealized loss on derivative
instruments, net (15,647) (27,072) (21,111) (41,205)
Income (loss) from
unconsolidated affiliates (3,617) 800 (2,870) 692
Total other expense (33,783) (39,875) (54,774) (62,361)
Loss from continuing operations
before income taxes and
discontinued operations (180,218) (24,110) (210,235) (45,838)
Income tax expense (benefit) 265 (860) (318) (1,457)
Loss from continuing
operations (180,483) (23,250) (209,917) (44,381)
Discontinued operations:
Gain (loss) on sale of
discontinued operations,
net of tax - (16) - 4
Net loss (180,483) (23,266) (209,917) (44,377)
Less net (income) loss
attributable to non-
controlling interest 8,165 (121) 12,046 208
Net loss attributable to Delta
common stockholders $(172,318) $(23,387) $(197,871) $(44,169)
Amounts attributable to Delta
common stockholders:
Loss from continuing
operations $(172,318) $(23,371) $(197,871) $(44,173)
Income (loss) from
discontinued operations,
net of tax - (16) - 4
Net loss $(172,318) $(23,387) $(197,871) $(44,169)
Basic income (loss)
attributable to Delta
common stockholders
per common share:
Loss from continuing operations $(0.89) $(0.23) $(1.35) $(0.49)
Discontinued operations - - - -
Net loss $(0.89) $(0.23) $(1.35) $(0.49)
Diluted income (loss)
attributable to Delta
common stockholders per
common share:
Loss from continuing
operations $(0.89) $(0.23) $(1.35) $(0.49)
Discontinued operations - - - -
Net loss $(0.89) $(0.23) $(1.35) $(0.49)
Weighted average common
shares outstanding:
Basic 193,028 101,057 146,248 90,563
Diluted 193,028 101,057 146,248 90,563
DELTA PETROLEUM CORPORATION
RECONCILIATION OF DISCRETIONARY CASH FLOW AND EBITDAX
(in thousands)
(unaudited)
THREE MONTHS ENDED
June 30, June 30,
2009 2008
CASH PROVIDED BY OPERATING ACTIVITIES $38,757 $42,287
Changes in assets and liabilities (3,778) (3,487)
Less net proceeds from offshore litigation
award (48,701) -
Exploration costs 471 1,933
Discretionary cash flow (deficiency)* $(13,251) $40,733
SIX MONTHS ENDED: June 30, June 30,
2009 2008
CASH PROVIDED BY OPERATING ACTIVITIES $32,849 $49,383
Changes in assets and liabilities (11,286) 17,000
Less net proceeds from offshore litigation
award (48,701) -
Exploration costs 1,531 2,935
Discretionary cash flow (deficiency)* $(25,607) $69,318
* Discretionary cash flow represents net cash provided by operating
activities before changes in assets and liabilities and offshore
litigation 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.
THREE MONTHS ENDED June 30, June 30,
2009 2008
Net loss $(180,483) $(23,266)
Minority Interest 8,165 (121)
Income tax expense (benefit) 265 (860)
Interest income (108) (3,388)
Interest and financing costs 15,883 9,676
Depletion, depreciation and amortization 36,107 27,960
Gain on offshore litigation award, sale of
drilling rig and other (1,643) 16
Unrealized loss on derivative instruments 15,647 27,072
Exploration, dry hole and impairment costs 107,092 2,363
EBITDAX** $925 $39,452
THREE MONTHS ENDED June 30, June 30,
2009 2008
CASH PROVIDED BY OPERATING ACTIVITIES $38,757 $42,287
Changes in assets and liabilities (3,778) (3,487)
Less net proceeds from offshore litigation
award (48,701) -
Interest net of financing costs 10,446 2,408
Exploration costs 471 1,933
Other non-cash items 3,730 (3,689)
EBITDAX** $925 $39,452
SIX MONTHS ENDED June 30, June 30,
2009 2008
Net loss $(209,917) $(44,377)
Minority Interest 12,046 208
Income tax benefit (318) (1,457)
Interest income (756) (5,258)
Interest and financing costs 32,957 18,613
Depletion, depreciation and amortization 68,721 54,642
Gain on offshore litigation award, sale of
drilling rig and other (32,928) (4)
Unrealized loss on derivative instruments 21,111 41,205
Exploration, dry hole and impairment costs 109,595 5,704
EBITDAX** $511 $69,276
SIX MONTHS ENDED June 30, June 30,
2009 2008
CASH PROVIDED BY OPERATING ACTIVITIES $32,849 $49,383
Changes in assets and liabilities (11,286) 17,000
Less net proceeds from offshore litigation
award (48,701) -
Interest net of financing costs 20,774 7,096
Exploration costs 1,531 2,935
Other non-cash items 5,344 (7,138)
EBITDAX** $511 $69,276
** 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, offshore litigation 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.
SOURCE Delta Petroleum Corporation
