EXHIBIT 99.1
[BETA OIL & GAS, INC. LOGO]
Beta Oil & Gas, Inc. Announces 2002 Results and Proved Reserves;
Provides Guidance for 2003
FOR IMMEDIATE RELEASE – March 5, 2003
Tulsa, Oklahoma – March 5, 2003 – Beta Oil & Gas, Inc. (“Company”) (NASDAQ:BETA) announced today the financial results of its fourth quarter and year ended December 31, 2002, as well as its year-end 2002 proved reserves and 2003 guidance.
Year End Results
For the year ended December 31, 2002, the Company had an approximate $7.3 million net loss attributable to common shareholders, or $.59 per diluted share, compared to a $9.3 million net loss attributable to common shareholders, or $.75 per diluted share, for the same period in 2001. The loss was primarily due to a fourth quarter non-cash, full cost ceiling impairment charge of $5.2 million, which included a $4.9 million impairment of the Company’s Jackson County, Texas unevaluated properties, and higher depletion expense. Revenues for the year ended 2002 were approximately $9.6 million compared to $13.6 million for the prior year. Earnings before interest, taxes, depletion, depreciation and amortization (EBITDA) were approximately $3.9 million, or $.32 per share, compared to $7.2 million or $.58 per share in 2001. Net loss attributable to common shareholders, excluding the non-cash impairment charge, for 2002 was approximately $2.1 million or $.17 per share, compared to 2001 net income attributable to common shareholders, excluding the non-cash impairment charge, of $.6 million, or $.05 per share.
Production volumes for the year ended December 31, 2002 were approximately 2.3 billion cubic feet (Bcf) of natural gas and 124.7 thousand barrels (MBbl) of oil compared to 2001 production of 2.5 Bcf of natural gas and 114.3 MBbl of crude oil. Average daily production was approximately 8.2 million cubic feet equivalent (MMcfe/d) of natural gas compared to 8.8 MMcfe/d of natural gas per day in 2001, a 6% decrease.
At December 31, 2002, the present value of the Company’s proved reserves, before income taxes, using a discount rate of 10% (PV 10), was $35.9 million, which was based on 2002 year-end prices of $31.23 per barrel (NYMEX) and $4.75 per MMbtu (Henry Hub spot price). This compares to a PV 10 of $31.3 million at December 31, 2001 using 2001 year-end prices of $19.78 per barrel (NYMEX) and $2.64 per MMbtu (Henry Hub spot price). Since there is no tax effect for either the 2002 or 2001 proved reserve PV 10 amounts, these amounts are also equal to our standardized measure of proved reserves. Approximately 97% of the natural gas reserves and approximately 99% of the oil reserves were classified as “proven developed”. The reserve mix at year-end 2002 was 80% natural gas and 20% oil.
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Total proved reserve volumes at December 31, 2002 were 14.7 Bcf of natural gas and 608.6 MBbl of oil, or 18.3 Bcfe of natural gas compared to December 31, 2001 proved reserves of 24.7 Bcf of natural gas and 836.8 MBbl of oil or 29.7 Bcfe of natural gas. Total proved reserves decreased approximately 11.4 Bcfe from the prior year primarily due to the reclassification of the reserves associated with the Company’s West Broussard prospect from proved undeveloped (PUD) to non-proven and 2002 production of approximately 3.0 Bcfe of natural gas.
At December 31, 2001, the PUD reserves for the West Broussard prospect were 7.3 Bcf of natural gas and 122 MBbl of oil. Unexpected water and sand production in adjacent wells to the prospect’s unit area were the main factors for reducing the certainty of the associated PUD reserves at West Broussard. However, the Company is currently a participant in the M.A. Failla #1 in the east unit of this prospect. Drilling activities commenced in late January 2003 and the well is currently drilling below 15,000 feet and is expected to reach total depth of approximately 15,800 by mid-March 2003. The Company has a 4.8% working interest in the well before payout, increasing to a 10.1% working interest after payout. Results of this well could support or lead to another revision of the classification of the reserves. Should the M.A. Failla #1 be successful and support an additional development well to the west, the Company is in a position to own a larger working interest in that well.
In late 2002, the Company began to shift its main emphasis from a focus on exploration activities to lower risk exploitation opportunities, primarily in the geographical areas the Company is active as operator. This change in priorities will reduce the capital budget allocated for drilling exploration projects in certain core areas, such as in the Frio, Yegua and Wilcox plays located in Jackson County, Texas. Accordingly, the Company recorded a $5.2 million non-cash impairment expense, or $.41 per diluted share, of which $4.9 million, or $.39 per diluted share, related to Jackson County, Texas, for the year ending December 31, 2002.
Fourth Quarter Results
For the fourth quarter 2002, the Company had an approximate $6.3 million net loss attributable to common shareholders, or $.51 per diluted share, compared to a $5.8 million net loss attributable to common shareholders, or $.47 per diluted share, for the same quarter in 2001. Revenues for the quarter ended 2002 were approximately $2.4 million compared to $2.6 million for the same quarter in 2001. EBITDA was approximately $.8 million, or $.06 per diluted share which was the same for the fourth quarter in 2001. The fourth quarter net loss attributable to common shareholders, excluding the non-cash full cost ceiling impairment charge, was approximately $1.1 million or $.09 per diluted share, compared to a net loss attributable to common shareholders of $1.3 million, excluding the non-cash full cost ceiling impairment charge, or $.10 per diluted share, for the same quarter in 2001.
(In Million of $)
| | Quarter Ended December 31, 2002
| | | Quarter Ended December 31, 2001
| | | Twelve Months Ended December 31, 2002
| | | Twelve Months Ended December 31, 2001
| |
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Revenues | | $ | 2.4 | | | $ | 2.6 | | | $ | 9.6 | | | $ | 13.6 | |
Cost and Expenses: | | | | | | | | | | | | | | | | |
Operating expense | | | .8 | | | | 1.0 | | | | 3.5 | | | | 3.8 | |
General and administrative | | | .8 | | | | .8 | | | | 2.2 | | | | 2.7 | |
Depreciation, depletion and amortization | | | 1.6 | | | | 1.4 | | | | 5.1 | | | | 5.2 | |
Full cost ceiling impairment | | | 5.2 | | | | 7.0 | | | | 5.2 | | | | 13.8 | |
Interest expense and other | | | .2 | | | | .2 | | | | .5 | | | | .7 | |
|
Loss before tax benefit | | | (6.2 | ) | | | (7.8 | ) | | | (6.9 | ) | | | (12.6 | ) |
Income tax benefit | | | — | | | | 2.1 | | | | — | | | | 3.5 | |
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Net loss | | | (6.2 | ) | | | (5.7 | ) | | | (6.9 | ) | | | (9.1 | ) |
Preferred dividends | | | (.1 | ) | | | (.1 | ) | | | (.4 | ) | | | (.2 | ) |
Net loss attributable to common shareholders | | $ | (6.3 | ) | | $ | (5.8 | ) | | $ | (7.3 | ) | | $ | (9.3 | ) |
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Per diluted common share data: | | | | | | | | | | | | | | | | |
Net loss attributable to common Shareholders | | $ | (.51 | ) | | $ | (.47 | ) | | $ | (.59 | ) | | $ | (.75 | ) |
Weighted average diluted common shares | | | 12.4 | | | | 12.4 | | | | 12.4 | | | | 12.4 | |
Special Items
The following table lists the special items reconciling EBITDA to income (loss) and reconciles net income (loss), excluding impairment charges, to net loss attributable to common shareholders.
(In Million of $)
| | Quarter Ended December 31, 2002
| | | Quarter Ended December 31, 2001
| | | Twelve Months Ended December 31, 2002
| | | Twelve Months Ended December 31, 2001
| |
Pro Forma EBITDA calculation: | | | | | | | | | | | | | | | | |
Income (loss) before tax (provision) benefit | | $ | (6.1 | ) | | $ | (7.8 | ) | | $ | (6.9 | ) | | $ | (12.5 | ) |
Add back: | | | | | | | | | | | | | | | | |
Interest expense and other | | | .1 | | | | .2 | | | | .5 | | | | .7 | |
Depreciation, depletion and amortization | | | 1.6 | | | | 1.4 | | | | 5.1 | | | | 5.2 | |
Full cost ceiling impairment | | | 5.2 | | | | 7.0 | | | | 5.2 | | | | 13.8 | |
EBITDA | | | .8 | | | | .8 | | | | 3.9 | | | | 7.2 | |
EBITDA per diluted common share | | $ | .06 | | | $ | .06 | | | $ | .32 | | | $ | .58 | |
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Pro Forma net income (loss) excluding impairment charge reconciliation: | | | | | | | | | | | | | | | | |
Net income (loss), excluding full cost ceiling impairment, attributable to common shareholders | | $ | (1.1 | ) | | $ | (1.3 | ) | | $ | (2.1 | ) | | $ | .6 | |
Net income (loss), excluding full cost ceiling impairment per diluted share | | $ | (.09 | ) | | $ | (.10 | ) | | $ | (.17 | ) | | $ | .05 | |
|
After tax effect of full cost ceiling impairment | | | (5.2 | ) | | | (4.5 | ) | | | (5.2 | ) | | | (9.9 | ) |
|
Net loss attributable to common shareholders | | $ | (6.3 | ) | | $ | (5.8 | ) | | $ | (7.3 | ) | | $ | (9.3 | ) |
Net loss per diluted share | | $ | (.51 | ) | | $ | (.47 | ) | | $ | (.59 | ) | | $ | (.75 | ) |
2003 Guidance
The Company estimates gross revenue for 2003 of $11.0 million based on an average natural gas price of $4.46 per Mcf and an average crude oil price of $25.29 per barrel, which takes into consideration basis differentials and discounts to NYMEX prices along with current hedge positions. The average underlying NYMEX natural gas and crude oil prices before adjustments are $4.58 per Mcf and $25.13 per barrel, respectively. The Company estimates its base average daily production rate for 2003 will be 7.1Mmcfe/d, which does not factor in any potential success from its South Louisiana unproven prospects, including West Broussard, Lake Boeuf or a second well at Lapeyrouse, or exploitation and rework activity associated with the West Edmond Hunton Lime Unit (WEHLU) located in Oklahoma.
The Company has budgeted $3.0 million for its 2003 capital expenditures as follows:
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| | • | | WEHLU, Oklahoma—$1.5 million for the participation in and drilling of three exploitation wells and rework projects. |
| | • | | Lapeyrouse field, Terrebonne Parish, Louisiana—$.6 million for the participation in the drilling of one development well and one extensional well. |
| | • | | West Broussard prospect, Lafayette Parish, Louisiana—$.3 million for the participation in the drilling of one exploration well. |
| | • | | Lake Boeuf prospect, Lafourche Parish, Louisiana—$.2 million for the participation in the drilling of one exploration well. |
| | • | | McIntosh County, Oklahoma—$.1 million for exploitation activity |
| | • | | TCM, Tulsa County, Oklahoma—$.1 million for recompletion and rework for six coal bed methane wells. |
| | • | | Other—$.2 million for various lease and rental requirements. |
Additionally, the Company has budgeted an additional $1.4 million for debt reduction and preferred dividend payments. The capital budget will be funded from the Company’s 2003 operating cash flow, which is estimated to be approximately $5.5 million. Current guidance for 2003 does not include any volume changes or expenditures from potential acquisitions or divestitures.
David Wilkins, President and CEO stated: “ We are making good progress on building a strong disciplined technical team that will methodically work to optimize the company’s existing assets thus creating a strong base on which we can build value for our shareholders. We will remain focused on ways to increase profitability in the most cost efficient manner. Our emphasis will remain on exploitation, however, we will maintain certain smaller interests in key exploration projects in which the Company has an existing interest. Disciplined spending on identified reserve and production growth opportunities along with continuous cost control remain a focal point. In addition, management continues to assess potential changes in the Company’s asset mix through property acquisitions, sell-down of interests with limited upside and other property sales where identified redeployment of sales proceeds will ramp up production levels in this period of high commodity prices. We do anticipate a continued strong outlook for oil and natural gas prices that will assist in our efforts to strengthen our balance sheet and increase overall operational performance in 2003.”
The Company plans to file the 2002 10K on or before March 28th, 2003 and will host a conference call to discuss 2002 operational results and the outlook for 2003. Additional information will be made regarding the conference call in a subsequent press release.
Beta Oil & Gas, Inc. is an independent energy company engaged in the production, exploration and development of oil and gas properties. For more information, please contact Steve Fischer at (918) 495-1011.
Forward-Looking Statement: This release includes certain statements that may be deemed to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements in this release, other than statements of historical facts, that address estimates of proved oil and gas reserves, future production, exploration drilling, exploitation activities, capital expenditures, gross unrisked reserve potentials, and events or developments that the company expects or believes are forward-looking statements. Although Beta believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those in forward-looking statements include oil and gas prices, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions. The Company has no obligation to update the statements contained in this report or to take action that is described herein or otherwise presently planned.
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