DPTR Delta Petroleum Corp. (MM)

DENVER, May 10, 2011 /PRNewswire/ -- Delta Petroleum Corporation (“Delta” or the “Company”) (NASDAQ Capital Market: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the first quarter 2011 and the initial production rate from the Mancos and Corcoran zones in the Delta 2B-233D well.

Carl Lakey, Delta’s CEO and President stated, “We are pleased to have posted another solid financial quarter driven by increased production from our core asset and a continued focus on cost control.  The current pricing environment bolstered by strength in natural gas liquids and condensate further enhances the financial performance of the asset.  Our EBITDAX for the first quarter was 30% higher than the first quarter 2010 when adjusted for discontinued operations.  In addition to our financial results from the first quarter, we continue to be excited about the shale resource potential in the Vega Area.  The completion information gathered from the 2C well and additional confirmation results from the 2B well justify additional capital deployment targeting the deeper shales and further validate our strategy to focus our resources on our core area.”

Delta believes the presentation of EBITDAX (a non-GAAP measure) provides useful information because it is commonly used by investors to assess financial performance and operating results of ongoing business operations.  Reconciliations of EBITDAX to net income (loss) and cash provided by (used in) operating activities, the most directly comparable GAAP financial measures, are provided within the financial tables of this press release.

VEGA AREA SHALE EVALUATION UPDATE

The Delta 2B-233D 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.  The well has been completed in 1,200 feet of shale below the Williams Fork in the Corcoran and the upper portion of the Mancos formation.  Gas production began on April 24 and sales commenced on April 29.  Even though the well continues to clean up and has not yet recovered 73% of the load water from the frac stimulation, the well achieved an initial production rate of 3.3 million cubic feet of gas per day (“MMcf/d”).  The Williams Fork section in the well will be completed when more production information is gathered from the Mancos and Corcoran formations.

The deeper Delta 2C-433D well drilled through the Mancos, Niobrara and Frontier formations and reached a total depth of 13,300 feet.  Completion activity on the well is now proceeding normally, with six additional frac stages scheduled to start later this week in the Niobrara and Mancos formations.  As shown on the Company’s investor presentation (which is posted on its website: http://www.deltapetro.com/corppresentation.html), the 2C well flowed 2 MMcf/d and 30 barrels per day (“Bbls/d”) of condensate at 6,700 pounds per square inch (“psi”) wellhead pressure from the two frac stages in the Frontier and lowest 20 feet of the Niobrara.  This represents less than 10% of the 4,000 feet of the gross hydrocarbon-bearing interval identified in the well.

Mr. Lakey further stated, “Building on the momentum of results from the shale wells to date, Delta will spud a third well targeting the shales in the recently formed 2,715 acre federal Sheep Creek Unit.  The well is expected to spud next week to a programmed depth of 13,500 feet and will target the Frontier, Niobrara, and Mancos shales.  The successful completion of this well will result in 93% of Delta’s acreage position in the Vega Area being held by production or held by unit, furthering Delta’s previously stated objective of solidifying our acreage position.”

Mr. Lakey continued, “We are very pleased to have initial production from the 2B well that has already substantially exceeded the rates seen in our best Williams Fork well.  It is essential to understand that only part of the Mancos and Corcoran zones are completed to date.  The Williams Fork section can be expected to add an additional 1.6 to 1.7 MMcfe/d of initial production.  We believe that shale resources from a vertical well can be added to our proven Williams Fork resource, improving both per well rates of return and ultimate resource potential in the Vega Area.  There is still significant additional information to learn as we continue to test and evaluate the shales in this well.  We believe the discovery of additional reserves beneath the Williams Fork formation adds significant intrinsic value to Delta.

“While production was up 4% over the fourth quarter, it was slightly beneath our expectations due to timing decisions on our inventory wells as a result of shale well activity.  We have maintained our cost control discipline as was demonstrated in the fourth quarter.  We continue to build on the momentum of improved financial performance from our Piceance asset and will continue to deploy our available capital to our core asset.  As part of this strategy, we will be marketing for sale our non-operated properties in Texas and the DJ Basin.  If the sale is completed, we plan to use the net proceeds for additional drilling activity in the Vega Area targeting the deeper shale formations and repayment of a portion of the outstanding balance on our senior secured credit facility.”

OPERATIONS UPDATE

In addition to the activity on the shale wells, during the first quarter 2011 the Company completed three wells from its drilled and uncompleted inventory in the Vega Area.  Current production from the Vega Area 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 completing the 2C well, drilling a third test well and completing the remaining two previously drilled wells.  The completions of the remaining two previously drilled wells are currently scheduled for June 2011; however, these plans could be altered depending on exploratory well results, with capital potentially being reallocated to additional shale activity.

Production for the second quarter 2011 is expected to be between 3.2 Bcfe and 3.4 Bcfe.

LIQUIDITY UPDATE

At March 31, 2011, the Company had $5.5 million in cash and approximately $22.4 million available under its amended credit facility.  The Company was in compliance with its financial covenants under its credit agreement.  The Company currently projects having sufficient capital under its credit facility as recently amended, combined with net cash from operating activities and through the sale of assets, to fund Delta’s operating expenses and the capital development described above and to maintain current debt service obligations through the remainder of 2011.  The 2011 capital expenditure program, beyond those expenditures currently planned and described herein, will be dependent upon well results, the sale of the Company’s non-core assets and the availability of capital to the Company.

In May 2011, the Company retained Macquarie Tristone to provide advisory services relating to the potential sale of certain of the Company’s non-operated assets located in the Texas Gulf Coast and DJ Basin regions.  The Company intends to use the net proceeds from any such sale for planned capital development activities in the Vega Area and to reduce indebtedness.

RESULTS FOR THE FIRST QUARTER 2011

For the quarter ended March 31, 2011, the Company reported production from continuing operations of 3.5 Bcfe, an increase of 4% when compared to the fourth quarter of 2010.   Revenue from oil and gas sales was $23.1 million, a decline of 22% when compared to the prior year period of $29.6 million, due to the divestiture of assets in the third quarter of 2010.  The average natural gas price received during the quarter ended March 31, 2011 decreased to $5.26 per thousand cubic feet (Mcf) compared to $5.85 per Mcf for the prior year period.  The average oil price received during the quarter ended March 31, 2011 increased to $86.26 per barrel compared to $71.26 per barrel for the prior year period.

The Company reported a first quarter net loss attributable to Delta common stockholders of ($27.8 million), or ($0.10) per diluted share, compared to a net loss attributable to Delta common stockholders of ($12.8 million), or ($0.05) per diluted share, in the first quarter of 2010.  The increase in net loss is primarily due to changes in unrealized gains and losses on derivative instruments offset by lower operating costs and interest expense.

FIRST QUARTER PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and costs per equivalent Mcf for the quarter ended March 31, 2011 and 2010 were as follows:

Lease Operating Expense.  Lease operating expenses for the quarter ended March 31, 2011 decreased to $4.6 million from $6.9 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 due to the divestiture of assets in the third quarter of 2010.  Lease operating expense per Mcfe for the quarter ended March 31, 2011 decreased to $1.33 per Mcfe from $1.67 per Mcfe for the prior year period.

Transportation Expense.  Transportation expense for the quarter ended March 31, 2011 increased to $4.0 million from $3.4 million in the prior year.  Transportation expense per Mcfe for the quarter ended March 31, 2011 increased 41% to $1.14 per Mcfe from $0.81 per Mcfe.  The increase on a per unit basis is primarily the result of a change in production mix related to the divestiture of assets in the third quarter of 2010 and changes to the Company’s Vega gas marketing contract.

Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization expense decreased 12% to $13.5 million for the quarter ended March 31, 2011, as compared to $15.3 million for the prior year period. Depletion expense for the quarter ended March 31, 2011 decreased to $12.9 million from $14.6 million for the quarter ended March 31, 2010 due to lower production volumes as a result of the divestiture of assets in the third quarter of 2010. The Company’s depletion rate increased from $3.53 per Mcfe for the quarter ended March 31, 2010 to $3.70 per Mcfe for the current year period primarily due to a decrease in reserves primarily attributable to the divestiture of assets in the third quarter of 2010.

General and Administrative Expense. General and administrative expense decreased 36% to $6.6 million for the quarter ended March 31, 2011, as compared to $10.3 million for the comparable prior year period. The decrease in general and administrative expense is attributed to a decrease in non-cash stock compensation expense and to reduced staffing as a result of attrition and a reduction in force since the first quarter of 2010 resulting in lower cash compensation expense.  For the quarter ended March 31, 2011, general and administrative expense included $2.3 million of non-cash equity based compensation compared to $3.4 million for the prior year period.

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 $71.2 million at March 31, 2011 is included in the consolidated balance sheets as a component of liabilities related to assets held for sale.

ADDITIONAL FINANCIAL INFORMATION

The following table summarizes the Company’s open derivative contracts at March 31, 2011:

INVESTOR CONFERENCE CALL

The Company will host an investor conference call on Wednesday, May 11, 2011 at 12:00 noon Eastern Time to discuss operating results for the first 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 May 11, 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 May 11, 2011 until May 19, 2011 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 450832.

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 in 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 “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 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, intended use of proceeds from potential sale of Texas Gulf Coast and DJ Basin assets; and anticipated production for second 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 contraction in 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, 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 investorrelations@deltapetro.com.

SOURCE Delta Petroleum Corporation