Delta 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.
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.
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.
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.
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