Delta Petroleum Corporation Announces 2010 Annual and Fourth Quarter Results

DENVER, March 16, 2011 /PRNewswire/ -- Delta Petroleum Corporation ("Delta" or the "Company") (Nasdaq: DPTR), an independent oil and gas exploration and development company, today announced its financial and operating results for the fourth quarter and full year 2010.

Carl Lakey, Delta's President and CEO stated, "We are very pleased with our results for the fourth quarter.  Our EBITDAX is 20% higher than the third quarter driven by lower operating and overhead costs, despite lower production related to asset sales and lower average Henry Hub gas prices in the quarter.  We have been committed to reducing our operating and overhead costs, and I'm pleased to state that we have been able to deliver such results.  We drove our LOE/Mcfe down by 38% compared to the third quarter.  Additionally, our overhead costs are down 25% from the third quarter.  We remain focused on sustaining costs at or near these levels for 2011.  We've also had very positive results from the well completion activity performed in the fourth quarter and to date in the first quarter of this year.  The larger frac design, which we call Gen IV, has increased our initial production and our estimated reserves per well.  We have completed a total of 16 wells with the Gen IV frac design and all have performed better than we would have expected under prior completion designs.  Thus, we expect first quarter production to increase 4% to 7% over the fourth quarter.  These new cost control measures substantially improve our EBITDAX and cash flow which, combined with increased production at the Vega Area, provide value to our shareholders."

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.

2010 YEAR-END RESERVES

For the year ended December 31, 2010, total estimated proved reserves as prepared by an independent third party engineering firm were 134 billion cubic feet equivalents ("Bcfe"), an increase of 17% from the prior year when adjusted for the 39 Bcfe divesture in the third quarter of 2010.  Estimated proved reserves were 91% natural gas, which includes related natural gas liquids, and were 92% proved developed, with a standardized measure of $192 million.  Approximately 92% of proved reserves are located in the Rocky Mountain region.  In addition to proved reserves, the Company estimates that total proved and probable reserves for the Vega Area, its core asset, have increased to 2.9 net trillion cubic feet equivalent ("Tcfe") from the Williams Fork section and above.  

See "Reserve Disclosure" below for more explanation with respect to the Company's probable reserves.

Prices used to calculate the Company's estimated proved reserves reflect the pricing methodology required under the SEC's reserve reporting rules which uses the trailing 12-month average of the first of the month price, or $3.95 per million British thermal units ("MMBtu") priced at Colorado Interstate Gas (CIG) and $79.61 per barrel of West Texas Intermediate (WTI) oil for 2010, in each case adjusted for differentials, contractual deducts, and similar factors.  

Total costs incurred in oil and gas operations during 2010 were $44.7 million, of which $42.4 million were drilling and completion related.  

Future net cash flows presented below are computed using first of the month 12-month historical average and costs.

*No income tax provision is included in the standardized measure calculation shown above as the Company does not project to be taxable or pay cash income taxes based on its available tax assets and additional tax assets generated in the development of its reserves because the tax basis of its oil and gas properties and NOL carryforwards exceeds the amount of discounted future net earnings.

RESERVE SENSITIVITIES

The Company internally performed price sensitivities to its reserve estimates using 2011 strip pricing as of December 31, 2010 with a four rig drilling program at its Vega asset and adding $1.00 and $2.00 to the NYMEX gas price.  All reserves that were included are limited to locations that meet the five-year drilling requirements.

LIQUIDITY UPDATE

At December 31, 2010, the Company had $15.7 million in cash and approximately $6.2 million available under its amended credit facility ($26.4 million available at March 16, 2011).  

On March 14, 2011, Delta entered into an amendment to the Macquarie Bank Limited ("MBL") Credit Agreement that increased the availability under the term loan at the time from $6.2 million to $25.0 million, and does not require repayments of the term loan until the January 2012 maturity date.  Specifically, among other changes, the amendment provided for an increase in the term loan commitment from $20.0 million to $25.0 million and removed the requirement that advances under the term loan be subject to approval of a development plan.  In addition, so long as Delta is not in default under the MBL Credit Agreement, Delta is not required to comply with certain cash management provisions, including the previous requirement to repay any term loan advances outstanding on a monthly basis with 100% of net operating cash flows.  

At December 31, 2010, DHS Drilling Company ("DHS") was out of compliance with debt covenants under its credit facility and entered into a Forbearance Agreement with its credit facility lender which expires on March 25, 2011.  Although the DHS facility is non-recourse to Delta, amounts outstanding under the DHS credit facility are classified as a current liability in the accompanying consolidated balance sheet as of December 31, 2010 as the amounts outstanding under the facility are due on August 31, 2011.  DHS continues discussions with its credit facility lender regarding amendments, waivers or other restructuring of the credit facility, but there can be no assurance that the lender will agree to any such amendments.  The Board of Directors of DHS has directed DHS management to explore the possible sale of the company or its assets.  

OPERATIONS UPDATE

Current production from the Vega Area exceeds 30.0 million cubic feet equivalent per day ("Mmcfe/d") net.  During the fourth quarter 2010 the Company completed eight wells from its drilled and uncompleted inventory in the Vega Area. Since year end, the Company has completed three of the inventory wells and currently expects to complete the remaining two drilled and uncompleted wells in the second quarter of 2011. With the use of the Company's improved frac technology, referred to as "Gen IV," currently 16 wells, or 8% of Delta's total producing wells in the Vega Area, are contributing approximately 39% of total production from the Vega Area.  Based on third party engineering data, the new Gen IV fracs are producing at rates that equate to an average gross estimated ultimate recovery ("EUR") of 1.6 Bcfe per well, an improvement from 1.15 Bcfe using Delta's prior completion methods.  

As previously disclosed, the Company has drilled an exploratory test well in the Vega Area to explore potential below the Williams Fork section and is now conducting completion activities on the well.  Additionally, during the current quarter Delta began drilling a second exploratory test well to continue to evaluate resource potential beneath the Williams Fork section.  Delta will release results of the exploratory test wells when appropriate.  

The Company recently terminated a contract with a water treatment service provider for the Vega Area, which resulted in the elimination of an ongoing future expense of approximately $500,000 per month for a ten year period in exchange for a one-time payment of $1.5 million.  The termination of this contract allows Delta to use alternative methods of water treatment and disposal that are more suitable for the amount of water that is currently being produced at the field, and management believes that the use of subsurface injection for water disposal is a much more viable and cost effective approach at the present time.  In addition to the water disposal wells that are currently utilized, the Company anticipates converting four wells in the field to water disposal wells and possibly drilling another.  The existing wells that are targeted for water disposal are old wells that have minimal or no gas production.  Delta is currently in the process of obtaining the necessary permits to inject produced water into the four existing wells, which will help maintain overall operating costs at the reduced levels.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

Delta will focus its current available capital for 2011 on completing the remaining five previously drilled wells, completing the exploratory test well, drilling a second exploratory test well to continue to evaluate potential below the Williams Fork section, and drilling a lease preservation well, all in the Vega Area.  The Company believes that the amounts available under its credit facility as recently amended, combined with net cash from operating activities, will provide it with sufficient liquidity to fund Delta's operating expenses and the capital development described above and maintain current debt service obligations.  The 2011 capital expenditure program, beyond those expenditures currently planned and described herein, will be dependent upon the commodity price environment, well results and the availability of capital to the Company.

Production for the first quarter 2011 is expected to be between 3.5 Bcfe and 3.6 Bcfe, exceeding the fourth quarter 2010 by 4% to 7%.  

RESULTS FOR THE FOURTH QUARTER 2010

For the quarter ended December 31, 2010, the Company reported production from continuing operations of 3.35 Bcfe, a decrease of 19% when compared with the fourth quarter of 2009 due to the divestiture of assets in the third quarter of 2010.  As a result, revenue from oil and gas sales declined 24% to $19.7 million from $26.0 million in the prior year quarter.  The average oil price received during the three months ended December 31, 2010 increased to $74.44 per barrel compared to $68.13 per barrel for the year earlier period.  The average natural gas price received during the three months ended December 31, 2010 decreased to $4.66 per thousand cubic feet (Mcf) compared to $4.74 per Mcf for the prior year period.  Revenue from contract drilling and trucking fees increased 300% to $17.0 million in the fourth quarter of 2010, versus $4.3 million in the fourth quarter of 2009.  

The Company reported a fourth quarter net loss attributable to Delta common stockholders of ($33.7 million), or ($0.12) per diluted share, compared with net loss attributable to Delta common stockholders of ($34.1 million), or ($0.12) per diluted share, in the fourth quarter of 2009.

FOURTH QUARTER 2010 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and costs per equivalent Mcf for the three months ended December 31, 2010 and 2009 were as follows:

Lease Operating Expense.   Lease operating expenses for the quarter ended December 31, 2010 were $3.7 million compared to $5.3 million for the prior year period.  The 31% decrease was the result of a decrease in water handling costs in the Vega Area due to the resumption of a development program and to a reduced working interest in the properties sold in the third quarter of 2010.  The average lease operating expense was $1.09 per Mcfe in the fourth quarter 2010 as compared to $1.28 per Mcfe for the year earlier period.

Transportation Expense.  Transportation expense for the quarter ended December 31, 2010 was $4.0 million, compared to $3.4 million for the prior year period, up 45% on a per unit basis from $0.83 per Mcfe to $1.20 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 Vega gas marketing contract that went into effect in October 2009 whereby gas is processed through a higher efficiency plant with higher costs.  Although the Vega area transportation costs increased on a per unit basis in the fourth quarter 2010 as a result of these operations, these costs were offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Depreciation, Depletion and Amortization – oil and gas.  Depreciation, depletion and amortization expense decreased 31% to $12.7 million for the quarter ended December 31, 2010, as compared to $18.5 million for the prior year period. Depletion expense for the quarter ended December 31, 2010 was $11.9 million compared to $17.7 million for the quarter ended December 31, 2009. The 33% decrease in depletion expense was primarily due to a 19% decrease in production from continuing operations and a 17% decrease in the depletion rate.  The unit-of-production depletion rate decreased to $3.56 per Mcfe for the quarter ended December 31, 2010 from $4.29 per Mcfe for the prior year period. The decrease is primarily due to improved economics from the use of improved fracturing methods and the changed mix of properties due to the divestiture of assets in the third quarter of 2010.    

General and Administrative Expense. General and administrative expense ("G&A") decreased 21% to $7.8 million for the quarter ended December 31, 2010, as compared to $9.9 million for the prior year period. The decrease in general and administrative expenses is primarily attributed to lower expenses incurred on employee benefits and wages from reductions in force during 2010. For the quarter ended December 31, 2010 G&A expense included $2.7 million of non-cash equity based compensation and $1.1 million of G&A expense related to DHS.  For the quarter ended December 31, 2009 G&A expense included $2.5 million of non-cash equity based compensation and $1.0 million G&A expense related to DHS.  Stand alone Delta cash G&A from the quarter ended December 31, 2010 decreased 38% from the quarter ended December 31, 2009.  

RESULTS FOR THE FULL YEAR 2010

For the year ended December 31, 2010, the Company reported total production from continuing operations of 14.8 Bcfe, which was a decrease of 21% from the previous year due to the divestiture of assets in the third quarter of 2010 and production declines in the Piceance Basin.  For the year ended December 31, 2010, oil and gas sales from continuing operations increased 14% to $94.4 million, compared with $82.7 million in the comparable period a year earlier.  The increase resulted from a 62% increase in the average gas price and a 35% increase in the average oil price.  Drilling and trucking revenue increased 289% to $53.2 million, from $13.7 million in the prior year period, as the result of the increase in third party rig utilization due to an increase in drilling activity attributable in particular to higher oil prices.

For the year ended December 31, 2010, the Company reported a net loss of ($182.3) million, or ($0.66) per diluted share, compared with a net loss of ($328.8 million), or ($1.56) per diluted share, for the year ended December 31, 2009.  

FULL YEAR 2010 PRODUCTION VOLUMES, UNIT PRICES AND COSTS

Production volumes, average prices received and costs per equivalent Mcf for the years ended December 31, 2010 and 2009 are as follows:

Lease Operating Expense.   Lease operating expenses for the year ended December 31, 2010 were $24.6 million compared to $26.4 million for the year earlier period, a decrease of $1.8 million; however, lease operating expenses increased on a per unit basis primarily due to the effect of fixed costs spread over a 21% decline in production volumes.  The average lease operating expense was $1.66 per Mcfe in 2010 as compared to $1.41 per Mcfe for the year earlier period.

Transportation expense.  Transportation expense for the year ended December 31, 2010 was $15.2 million, compared to prior year costs of $10.1 million, up 91% on a per unit basis from $0.54 per Mcfe to $1.03 per Mcfe.  The increase on a per unit basis is primarily the result of changes to the Vega gas marketing contract that went into effect in October 2009 whereby gas is processed through a higher efficiency plant.  Although the Vega area transportation costs increased on a per unit basis in 2010 as a result of these operations, these costs were offset by higher revenues in the Vega area from improved natural gas liquids recoveries and a greater percentage of liquids proceeds retained.

Depreciation, Depletion and Amortization – oil and gas.  Depreciation, depletion and amortization expense decreased 28% to $58.3 million for the year ended December 31, 2010, as compared to $81.3 million for the year earlier period. Depletion expense for the year ended December 31, 2010 was $55.0 million compared to $78.4 million for the year ended December 31, 2009. The 30% decrease in depletion expense was primarily due to a 21% decrease in production from continuing operations and an 11% decrease in the depletion rate.  The depletion rate decreased to $3.73 per Mcfe for the year ended December 31, 2010 from $4.19 per Mcfe for the year earlier period. The decrease is primarily due to a change in the mix of Delta properties as a result of the divestiture of assets in the third quarter of 2010 and additional Rockies reserves recorded in 2010 as a result of completion activities and use of improved fracturing methods.

General and Administrative Expense.   General and administrative expense decreased slightly to $41.1 million for the year ended December 31, 2010, as compared to $41.4 million for the comparable prior year period.  While the Company experienced a decrease in general and administrative expenses primarily attributable to lower expenses incurred on employee benefits and wages from reductions in force during 2010 and 2009, such decrease was offset by significant costs associated with Delta's 2010 strategic alternatives process and bad debt expense recorded by DHS. The Company expects further reductions to full year cash general and administrative expenses in 2011 as cost saving measures implemented in 2010 take full effect in 2011.  

ADDITIONAL FINANCIAL INFORMATION

The following table summarizes the Company's open derivative contracts at December 31, 2010, required pursuant to the Company's credit agreement:

The following table summarizes the Company's current open derivative contracts for natural gas liquids that were put in place during the first quarter of 2011 required pursuant to the Company's credit agreement:

INVESTOR CONFERENCE CALL

The Company will host an investor conference call on Thursday, March 17, 2011 at 12:00 noon Eastern Time to discuss operating results for the fourth quarter and full year 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 March 17, 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 March 17, 2011 until March 25, 2011 by dialing 877-344-7529 (international callers dial 412-317-0088) and entering the conference ID 448373.  

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."

RESERVE DISCLOSURE

The Company does not plan to include probable reserve estimates in its filings with the SEC.  The Company has provided internally generated estimates for probable reserves in this release. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Delta's probable reserve estimates are determined using strip pricing which it uses internally for planning and budgeting purposes. The Company's estimate of probable reserves is provided in this release because management believes it is useful additional information that is widely used by the investment community in the valuation, comparison and analysis of companies.  

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, anticipated future operating and overhead costs, cost control measures, liquidity requirements and availability of capital, drilling and completion activity, anticipated impact of new frac designs, expected decreases in general and administrative expenses and anticipated production for 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 and its working capital needs, 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 disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.  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].

* 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 Delta's business.  The Company believes that it provides additional information regarding its ability to meet 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.

**EBITDAX represents net income (loss) before non-controlling 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, gain on discontinued operations, 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 the Company's business.  Delta believes that it provides additional information regarding its ability to meet 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 the Company's lenders pursuant to its bank credit agreement and is used in the financial covenants in its bank credit agreement and Delta's 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