Brigham Reports Lower Profit for 2006
Brigham Exploration Company late Monday announced financial results for the year-end and quarter ended December 31, 2006.
YEAR-END 2006 RESULTS
Average daily production volumes for 2006 were 36.8 MMcfe per day, up 11% when compared to 2005. Revenues from the sale of oil and natural gas including hedge settlements for 2006 were $103.6 million, which represents a 7% increase when compared to last year. Higher production volumes and hedge settlement gains increased revenue by $11.1 million and $8.0 million, respectively, while lower commodity prices decreased revenue by $12.3 million.
Our average realized price for natural gas in 2006 was $7.09 per Mcf, which included a $0.35 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in 2005 of $7.97 per Mcf, which included a $0.32 per Mcf loss due to the settlement of our natural gas derivative contracts. Our average realized price for oil for 2006 was $64.39 per barrel, which included a $0.35 per Bbl gain due to the settlement of our oil derivative contracts. This compares to an average realized price in 2005 of $51.95, which included a $2.78 per barrel loss due to the settlement of oil derivative contracts last year.
Our production costs, which include costs for operating and maintaining (O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes, were up $0.23 per Mcfe, or 26%, when compared to 2005. O&M expenses increased $0.16 per Mcfe, or 34%. Increased costs associated with salt water disposal, equipment rental, chemical testing and treating, and well service and repair accounted for 69% of the increase in O&M expense. Ad valorem taxes increased $0.03 per Mcfe, or 33%, due to an increase in property valuations for our oil and natural gas properties due to higher commodity prices.
Our general and administrative (G&A) expense for 2006 was 43% higher than 2005. G&A expense increased primarily because of $1.6 million of non-cash employee compensation expense associated with our 2006 adoption of SFAS 123R, which deals with the change in accounting methodology for employee stock option expense. G&A expense also increased because of increases in payroll and benefits associated with higher employee retention costs and, to a lesser extent, an increase in the number of employees. These increases resulted in our G&A expense increasing by $0.14 per Mcfe, or 30%.
Our depletion expense for 2006 was 39% higher than 2005. Approximately 72% of the increase in our depletion expense for 2006 was due to an increase in our depletion rate while the remaining 28% of the increase was due to an increase in our production volumes. The increase in depletion rate is attributable to an increase in finding and development costs incurred in 2006 and an increase in future development costs associated with our year-end 2006 proved reserves.
Our net interest expense for 2006 was 143% higher than last year. This increase was primarily due to interest incurred on our 9 5/8% senior notes due 2014 ("Senior Notes"), which we issued in April 2006. The issuance of the Senior Notes resulted in an increase in our weighted average debt outstanding and our weighted average cost of debt. Our weighted average debt outstanding for 2006 was $123.0 million versus $80.2 million in 2005. In addition, we wrote-off approximately $1.0 million in subordinated note issuance costs associated with the termination of the subordinated credit facility in April 2006.
We recorded deferred income tax expense of $12.7 million in 2006 compared to deferred income tax expense of $15.0 million in 2005. Although overall tax expense was down relative to 2005, our effective tax rate increased due to our adoption of the Texas state margin tax in 2006, which required us to record $1.3 million of deferred margin tax in 2006 to account for the cumulative differences between book and tax accounting for periods prior to and including December 31, 2006.
Our reported net income for 2006 was $19.8 million ($0.43 per diluted share) versus net income of $27.4 million ($0.63 per diluted share) for the same period last year. Net income for 2006 includes $3.5 million after-tax ($5.8 million before-tax) in unrealized gains on derivatives. Excluding the impact of unrealized hedging gains, net income for 2006 would have been $16.3 million ($0.36 per diluted share).
As of December 31, 2006, we had $4.3 million in cash, $25.9 million of debt outstanding under our senior credit facility and a net debt to book capitalization ratio of 38%.
In 2006, we spent $184.6 million on oil and gas capital expenditures, which represents a 56% increase from 2005. Oil and gas capital expenditures for 2006 and 2005 were:
Twelve Months Ended December 31, 2006 2005 (in thousands) Drilling $ 142,338 $ 90,873 Net land and seismic 31,683 19,641 Capitalized costs 9,954 6,789 Capitalized SFAS 143 ARO 609 1,324 ---------- ---------- Total oil and gas capital expenditures $ 184,584 $ 118,627 ========== ==========
FOURTH QUARTER 2006 RESULTS
Our average net daily production volumes for the fourth quarter 2006 were 38.8 MMcfe per day, down 5% when compared to the fourth quarter 2005. Revenues from the sale of oil and natural gas including hedge settlements for the fourth quarter 2006 were down 29% to $26.0 million when compared to the fourth quarter 2005. Lower realized prices and production volumes decreased revenues by $12.0 and $1.9 million, respectively, while hedge settlement gains increased revenues by $3.4 million.
Our average realized price for natural gas for the fourth quarter 2006 was $7.00 per Mcf, which included a $0.36 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the fourth quarter 2005 of $10.02, which included a $0.71 per Mcf loss due to the settlement of our natural gas derivative contracts. During the fourth quarter 2006, our average realized price for oil was $56.09 per barrel, which included a $1.38 per barrel gain due to the settlement of our oil derivative contracts. This compares to an average realized price in the fourth quarter 2005 of $57.71, which included a $0.95 per barrel loss due to the settlement of our oil derivative contracts.
Our fourth quarter 2006 production costs were up 1% on a per unit basis when compared to the fourth quarter 2005. A $0.24 per Mcfe increase in our O&M expenses was offset by a $0.23 per Mcfe decrease in our production taxes. Increases in salt water disposal, compressor and equipment rental, and well service and repair accounted for 64% of the per unit increase in O&M expense. The decrease in production taxes is attributable to both lower production volumes and an increase in the level of severance tax refunds approved by states in the fourth quarter 2006 as compared to the fourth quarter 2005.
Our G&A expense for the fourth quarter 2006 was 8% higher than the fourth quarter 2005. G&A expense increased primarily because of $0.4 million of non- cash employee compensation expense associated with our 2006 adoption of SFAS 123R.
Our depletion expense for the fourth quarter 2006 was $1.5 million higher than the fourth quarter 2005. Depletion increased by $2.1 million due to an increase in our depletion rate and was partially offset by a $0.6 million decrease due to lower production volumes.
Our net interest expense for the fourth quarter 2006 increased by $1.5 million. This increase was primarily due to our higher weighted average debt outstanding and our higher weighted average interest cost associated with our Senior Notes. Our weighted average debt outstanding for the fourth quarter 2006 was $149.6 million compared to $91.9 million for the comparable period last year.
We recorded deferred income tax expense of $2.8 million in the fourth quarter of this year compared to deferred income tax expense of $6.5 million in the fourth quarter last year. The decrease in our deferred income tax expense was primarily due to lower fourth quarter 2006 income before income taxes.
Our net income for the fourth quarter 2006 was $5.0 million ($0.11 per diluted share) compared to net income of $11.9 million ($0.26 per diluted share) in the fourth quarter 2005. Fourth quarter 2006 net income includes $1.8 million after-tax ($2.9 million before-tax) in unrealized commodity derivative gains. Excluding the impact of these unrealized derivative gains, net income for the quarter would have been $3.2 million ($0.07 per diluted share).
2006 PROVED RESERVES
Our estimated net proved reserve volumes at December 31, 2006 totaled 146.5 Bcfe of which approximately 82% was natural gas. During 2006, we added approximately 26.5 Bcfe in net proved reserves and replaced 200% of the 13.3 Bcfe of production. Our 2006 net proved reserve additions included 26.8 Bcfe of extensions, discoveries and other additions which were partially offset by 0.3 Bcfe of revisions to prior estimates. Our estimated net proved developed reserves at December 31, 2006 totaled 81.0 Bcfe and our net proved undeveloped reserves totaled 65.5 Bcfe. With net proved undeveloped reserves remaining flat from 2005 to 2006, our net proved developed reserves increased 19% from the prior year and represented 55% of total proved reserves at year- end 2006 versus 51% at year-end 2005.
Equivalent Reserves (MMcfe) 2006 Beginning Proved Reserves 133,223 Extensions, discoveries & other additions 26,764 Revisions of prior estimates (281) Production (13,254) ------- 2006 Ending Proved Reserves 146,452 =======
At year-end 2006, the standardized measure and the pre-tax present value ("Pre-tax PV10% Value") of our estimated proved reserves were $302.7 million and $338.5 million, respectively. For 2006, these measures were calculated using a West Texas Intermediate Sweet price of $61.06 per barrel and a Henry Hub natural gas price of $5.48 per MMBtu.
At December 31, 2006 Standardized measure of discounted future net cash flows $ 302.7 Add present value of future income tax discounted at 10% 34.6 FAS 143 assumption differences 1.2 -------- Pre-tax PV10% $ 338.5 ========
Pre-tax PV10% Value is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes discounted using a 10% discount rate. Pre-tax PV10% Value is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that Pre-tax PV10% Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that Pre-tax PV10% Value is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and natural gas industry calculate Pre-tax PV10% Value on the same basis. Pre-tax PV10% Value is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes.
FULL YEAR AND FIRST QUARTER 2007 FORECASTS
The following forecasts and estimates of our first quarter 2007 and full year 2007 production volumes are forward looking statements. We currently expect our first quarter 2007 production volumes to average between 37.5 MMcfe per day and 40.0 MMcfe per day. We expect full year 2007 production volumes to average between 40.0 MMcfe per day and 45.0 MMcfe per day.
For the first quarter 2007, lease operating expenses are projected to be $0.82 per Mcfe based on the mid-point of our production guidance, production taxes are projected to be approximately 5.5% of pre-hedge oil and natural gas revenues, and general and administrative expenses are projected to be $2.1 million ($0.62 to $0.58 per Mcfe).
Bud Brigham, Brigham's CEO and President, commented, "During 2006, we made very substantial long-term investments in acreage, 3-D seismic, and the drilling of early wells in our emerging resource plays. We expect these investments to pay dividends for us in 2007 and subsequent years. We also aggressively developed our proved undeveloped reserves in 2006 with very good results. While this negatively impacted our total proved finding cost, it generated strong growth in proved developed reserves. Specifically, regarding our focus plays, the Texas Frio underperformed for us during 2006. However, we once again achieved exceptional results in the Vicksburg, including low total proved finding costs and strong rates of return on our drilling investments. Our total proved drilling finding costs were attractive in our other focus plays including Southern Louisiana as well as the Hunton, Springer and the Granite Wash plays of the Anadarko Basin. As evidenced by our capital plan for 2007, our drilling this year will be focused in those plays that have generated our strongest returns, led by the Vicksburg."
Brigham Exploration Company is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore and develop onshore domestic natural gas and oil provinces.
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