Delta Petroleum Corporation Announces Second Quarter 2011 Results

DENVER, Aug. 4, 2011 /PRNewswire/ -- Delta Petroleum Corporation ("Delta" or the "Company") (NASDAQ Capital Market: DPTRD), an independent oil and gas exploration and development company, today announced its financial and operating results for the second quarter 2011.  

Carl Lakey, Delta's CEO and President stated, "We are pleased to provide our shareholders with another solid operating quarter coupled with the accomplishment of some very important strategic steps.  We sold our remaining non-core assets, which reduced our leverage and provided sufficient liquidity to continue our deep shale evaluation and development in the Vega Area.  While the strategic alternatives process, the 2C well results, and the Netherland Sewell report were all announced subsequent to the end of the quarter, much of the efforts that went into those steps occurred in the second quarter.  The 2B and 2C well results and Netherland Sewell's report are very important contributions that support Delta's intrinsic value and aid our strategic alternatives process."

VEGA AREA SHALE EVALUATION UPDATE

As previously announced, the Delta 2C well began producing hydrocarbons on Wednesday, July 20, at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which was choke-restricted with a 7/64 of an inch choke and 8,360 psi of flowing tubing pressure.  Gas sales from the well began on Thursday, July 21 from the Niobrara and Frontier formations only.  The well is currently producing between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure.  The well choke is currently set at 9/64 of an inch.  The Mancos shale, Corcoran and Williams Fork formations remain uncompleted.

The Delta 2B well in the Vega Area of the Piceance Basin drilled through a portion of the Mancos formation and reached total depth of 10,700 feet.  Below the Williams Fork the well was completed in 1,200 feet of shale in the Corcoran and the upper portion of the Mancos formation.  Gas production began on April 24 and sales commenced on April 29.  As announced on May 10, the 2B well experienced sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations.  The well is currently producing 0.6 MMcf/d.  The information available indicates that the natural fractures in the 2B well may have prematurely closed by the high flow rate (6 MMcf/d) during initial flowback activities, which has subsequently hindered production.  The Company is currently evaluating refracturing the well in the Mancos and Corcoran formations to reestablish higher production levels in the well.

The Company is currently drilling the 12B well.  The current depth is approximately 8,500 feet with a target depth of 13,000 feet.  It is expected that the target depth will reach the Frontier formation.  Total depth is expected to be reached during September.  Once completed, this well will hold the acreage of the federal Sheep Creek Unit and bring the Company's Vega leasehold up to 95% held by production.  

STRATEGIC ALTERNATIVES UPDATE

On July 6, 2011, Delta announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process aimed at maximizing shareholder value and dealing with the Company's 2012 debt maturities. Through this process, the Board of Directors is evaluating all opportunities available, including a potential sale of the Company.  The process is in its early stages and the Company does not expect to make further public comment regarding the process until the Board of Directors has approved a specific transaction or otherwise determines that disclosure of significant developments, if any, is appropriate.

OPERATIONS UPDATE

Current production of the Company approximates 28 million cubic feet equivalent per day (MMcfe/d) net.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

Delta will focus its current available capital for the remainder of 2011 on drilling and completing the 12B well and completing the remaining two previously drilled Williams Fork wells.  The completions of the remaining two previously drilled wells have been postponed to the fourth quarter of 2011; however, these plans could be altered depending on shale well results, with capital potentially being reallocated to additional shale activity.  Developments related to the strategic alternatives process may also affect current capital spending plans.

Production for the third quarter 2011 is expected to be between 2.6 Bcfe and 2.7 Bcfe.

LIQUIDITY UPDATE

At June 30, 2011, the Company had $3.9 million in cash and approximately $18.0 million available under its amended credit facility.  During the second quarter, Delta received $43.2 million from the sale of non-core assets.  The proceeds were used to pay down the facility, close out certain oil derivative positions and for development activity in the Company's Piceance Basin projects.  The Company expects to have sufficient capital under its credit facility, combined with proceeds from the non-core asset sale and net cash from operating activities, to fund Delta's operating expenses and the current capital development described above and to maintain its debt service obligations through the remainder of 2011.  

RESULTS FOR THE SECOND QUARTER 2011

For the quarter ended June 30, 2011, the Company reported total production of 3.2 Bcfe.  Production from continuing operations was 2.8 Bcfe, remaining flat when comparing second quarter 2011 to the prior year period.  Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared to the prior year period of $14.8 million.  The average natural gas price received during the quarter ended June 30, 2011 increased to $5.31 per thousand cubic feet (Mcf) compared to $4.92 per Mcf for the prior year period.  The average oil price received during the quarter ended June 30, 2011 increased to $86.87 per barrel compared to $58.29 per barrel for the prior year period.  

The Company reported a second quarter net loss attributable to Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter of 2010.  The decrease in net loss is primarily due to a decrease in dry hole costs and impairments and a decrease in operating expenses, as well as discontinued operations.  

SECOND QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and costs per equivalent Mcf for the quarter ended June 30, 2011 and 2010 were as follows:

Lease Operating Expense.  Lease operating expenses for the three months ended June 30, 2011 decreased to $3.6 million from $6.1 million in the prior year period primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities.  As a result, lease operating expenses per Mcfe in the Vega Area declined from $2.18 per Mcfe for the three months ended June 30, 2010 to $0.87 per Mcfe for the three months ended June 30, 2011.  Overall, lease operating expense per Mcfe from continuing operations for the three months ended June 30, 2011 decreased to $1.28 per Mcfe from $2.19 per Mcfe.

Transportation Expense.  Transportation expense for the three months ended June 30, 2011 decreased to $3.6 million from $4.4 million in the prior year.  Transportation expense per Mcfe for the three months ended June 30, 2011 decreased 17% to $1.30 per Mcfe from $1.57 per Mcfe.  The decrease on a per unit basis is primarily the result of adjustments in the prior year that did not recur in the current year.  

Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization expense decreased 13% to $10.5 million for the three months ended June 30, 2011, as compared to $12.1 million for the comparable year earlier period. Depletion expense for the three months ended June 30, 2011 decreased to $9.8 million from $11.2 million for the three months ended June 30, 2010 primarily due to higher reserves as a result of recent drilling and completion activity in the Vega Area.  Accordingly, the Company's depletion rate decreased from $4.03 per Mcfe for the three months ended June 30, 2010 to $3.54 per Mcfe for the current year period.

Realized Loss on Derivative Instruments, Net.   During the three months ended June 30, 2011, the Company recognized a $5.0 million loss associated with settlements on derivative contracts. Included in this loss was $3.3 million paid to settle a portion of Delta's oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 non-core asset sale.  During the three months ended June 30, 2010, the Company recognized a $601,000 loss associated with settlements on derivative contracts.

General and Administrative Expense. General and administrative expense decreased 39% to $6.5 million for the three months ended June 30, 2011, as compared to $10.6 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force since the second quarter of 2010 resulting in lower cash compensation expense.

RESULTS FOR THE SIX MONTHS ENDED JUNE 30, 2011

The Company reported a six month net loss attributable to common stockholders of ($28.8 million), or ($1.03) per share, compared with a net loss attributable to common stockholders of ($162.5 million), or ($5.90) per share, in the six months ended June 30, 2010.  

For the six months ended June 30, 2011, the Company reported production from continuing operations of 5.78 Bcfe.  Revenue from oil and gas sales was $34.6 million, remaining flat when compared to the prior year period.  The average natural gas price received during the six months ended June 30, 2011 decreased to $5.31 per Mcf compared to $5.49 per Mcf for the year earlier period.  The average oil price received during the six months ended June 30, 2011 increased to $82.31 per Bbl compared to $59.60 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, 2011 and 2010 are as follows:

Lease Operating Expense.   Lease operating expenses for the six months ended June 30, 2011 decreased 34% to $7.0 million as compared to $10.5 million in the year earlier period.  The decrease is primarily due to lower water handling costs in the Vega Area as a result of the resumption of development activities and improved water handling facilities.  As a result, lease operating expense per Mcfe in the Vega Area declined from $1.74 per Mcfe for the six months ended June 30, 2010 to $0.88 per Mcfe for the six months ended June 30, 2011.  Overall, lease operating expense per Mcfe from continuing operations for the six months ended June 30, 2011 decreased to $1.20 per Mcfe from $1.80 per Mcfe for the comparable year earlier period.

Transportation Expense.  Transportation expense for the six months ended June 30, 2011 was $7.6 million comparable to $7.6 million in the prior year.  Transportation expense per Mcfe for the six months ended June 30, 2011 increased slightly to $1.31 per Mcfe from $1.30 per Mcfe.

Depreciation, Depletion, Amortization and Accretion – Oil and Gas.   Depreciation, depletion and amortization expense decreased 6% to $22.5 million for the six months ended June 30, 2011, as compared to $23.9 million for the comparable year earlier period.  Depletion expense for the six months ended June 30, 2011 was $21.2 million compared to $22.3 million for the six months ended June 30, 2010. The Company's depletion rate decreased from $3.81 per Mcfe for the six months ended June 30, 2010 to $3.67 per Mcfe for the current year period primarily due to higher reserves as a result of the Company's recent drilling and completion activity in the Vega Area.

Realized Loss on Derivative Instruments, Net.   During the six months ended June 30, 2011, the Company recognized a $5.5 million loss associated with settlements on derivative contracts compared to a $4.7 million loss for the comparable prior year period.  Included in the June 30, 2011 loss was $3.3 million paid to settle a portion of Delta's oil derivative contracts outstanding from July 2011 to December 2013 as a requirement to the amended MBL Credit Agreement completed in conjunction with the 2011 non-core asset sale.

General and Administrative Expense.   General and administrative expense decreased 37% to $13.1 million for the six months ended June 30, 2011, as compared to $20.9 million for the comparable prior year period. The decrease in general and administrative expenses is attributed to a decrease in non-cash stock compensation expense, lower corporate consulting fees and to reduced staffing as a result of attrition and a reduction in force during 2010 resulting in lower cash compensation expense.

DHS DRILLING COMPANY

The Board of Directors of DHS Drilling Company engaged transaction advisors to explore a strategic alternatives process focused on a sale of DHS or substantially all of its assets. In accordance with accounting standards, the financial position and results of operations relating to DHS have been reflected as assets and liabilities held for sale and discontinued operations in the accompanying consolidated balance sheets and statements of operations.  The DHS credit facility debt of $69.9 million at June 30, 2011 is included in the consolidated balance sheets as a component of liabilities related to assets held for sale.  The DHS credit facility debt is non-recourse to Delta.  

ADDITIONAL FINANCIAL INFORMATION

The following table summarizes the Company's open derivative contracts at June 30, 2011:

INVESTOR CONFERENCE CALL

The Company will host an investor conference call today, Thursday, August 4, 2011 at 12:00 noon Eastern Time (10:00 am Mountain Time) to discuss financial and operating results for the second quarter 2011.

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 4, 2011.  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 4, 2011 until August 12, 2011 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 10002277.  

ABOUT DELTA PETROLEUM

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 Capital Market System under the symbol "DPTRD" until on or around August 10, 2011, when the symbol will return to "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, business objectives and strategies, including our focus on the Vega Area of the Piceance Basin, as well as statements regarding our strategic alternatives process, possible value creation and resource potential, anticipated future operating and overhead costs, liquidity requirements and availability of capital, drilling and completion activity and anticipated timing, anticipated sources and uses of capital, and anticipated production for third quarter 2011.  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 the Company's credit facility, its working capital needs and in respect of the possible redemption of its senior convertible notes, the demand for natural gas in the United States, 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, regulations that might be adopted in the future that could, among other things, significantly limit or curtail hydraulic fracturing techniques used in the Piceance Basin, as well as general market conditions, competition and pricing.  The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to characterize as proved reserves only those accumulations that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions, and that are part of an approved five-year development plan.  Please refer to the Company's report on Form 10-K for the year ended December 31, 2010 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 [email protected].

SOURCE Delta Petroleum Corporation

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