Item 3.
Legal Proceedings
We are not currently a party to any material legal proceeding of which we are aware.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
There were no matters submitted to stockholders during the quarter ended December 31, 2003.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity and Related Stockholder Matters
Our common stock, $0.01 par value, is listed on the New York Stock Exchange under the symbol “EAC”. The following table sets forth quarterly high and low sales prices of our common stock for each quarterly period of 2003 and 2002:
On February 27, 2004, we had approximately 202 shareholders of record.
Recent Sale and Repurchase of Securities
On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.
Dividends
No dividends have been declared or paid on our common stock. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, and plans for expansion. The declaration and payment of dividends is restricted by our existing credit agreement, the indenture governing our 8 3/8% notes, and any future dividends may also be restricted by future agreements with our lenders.
Item 6.
Item 6.
Selected Financial Data
The following selected consolidated financial data should be read in conjunction with “Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the consolidated financial condition and results of operations of Encore Acquisition Company should be read in conjunction with the historical financial information provided in the consolidated financial statements and accompanying notes, as well as the business and properties descriptions in Items 1 and 2 of this Report.
Overview
We engage in the acquisition, development, exploitation and production of onshore North American oil and natural gas reserves. We remain determined to execute our business strategy of maintaining an active low-risk development drilling program, maximizing existing reserves and production through high-pressure air injection projects, expanding our reserves and production through a disciplined acquisition program, and cost control through efficient and safe operations.
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Oil prices remained strong in 2003. The average oil price for the NYMEX futures market was $31.04 and $26.08 per barrel for 2003 and 2002, respectively. The average natural gas price for the NYMEX futures market was $5.50 and $3.36 per MMBTU for 2003 and 2002, respectively. Commodity prices are impacted by many factors that are outside of our control. It is very difficult for us to predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by hedging.
In 2003, we were able to expand our Mid Continent area by acquiring a non-operated interest in natural gas properties in North Louisiana. We are optimistic both about how well this particular asset, Elm Grove, fits in our portfolio, and by the possibilities of additional acquisitions in the region. Elm Grove complements our existing asset base in many ways. We believe it contains a solid, predictable production base along with a large number of low risk infill drilling opportunities that are currently being exploited.
Also in 2003, we continued to see positive results from our initial high-pressure air injection project at our Pennel unit of the CCA, and have approved expanding it to other areas in the CCA. We began phase one of our second HPAI project in Little Beaver during December 2003 and phase one and phase two
should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of proved undeveloped oil reserves associated with high pressure air at year end 2003 related to the Little Beaver unit project. High pressure air injection contributed to our FD&A cost of $7.42 per BOE during 2003. For the long term, we believe that high-pressure air injection technology can be applied throughout the Cedar Creek Anticline.
2003 Highlights
Our financial and operating results for the year ended December 31, 2003 included the following highlights:
•
Oil and natural gas reserves increased 10% to 140,890 MBOE. During 2003, we added 20.7 MMBOE at a FD&A cost of $7.42 per BOE, replacing 255% of the 8.1 MMBOE produced in 2003. Including revisions, the development program added 14.4 MMBOE (178% of our production) at a cost of $6.86 per BOE. Included in our reserve additions are 12.5 MMBOE of high-pressure air volumes. The 12.5 MMBOE represents the first reserves related to our high-pressure air injection program in the Cedar Creek Anticline of Montana and North Dakota. Our three year FD&A costs, including revisions, are $5.60 per BOE with a reserve replacement ratio of 329%. Oil reserves accounted for 84% of total proved reserves, and 78% of proved reserves are proved developed. Our reserve-to-production ratio is 17 years for total proved reserves and 14 years for proved developed reserves.
•
Production volumes for the year increased 10% to 8.1 MMBOE (22,218 BOE per day), compared with 2002 production of 7.4 MMBOE (20,273 BOE per day). Oil represented 81% and 82% of our total BOE production in 2003 and 2002, respectively. The increase in production is due to our continued successful development and exploitation program as well as the Elm Grove acquisition.
•
Net income for the full year of 2003 increased 69% to $63.6 million, or $2.10 per diluted share, on revenues of $220.1 million. Net income for the year ended December 31, 2003 includes a $0.9 million ($0.03 per diluted share) cumulative effect of accounting change resulting from the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003. This compares to full year 2002 net income of $37.7 million, or $1.25 per diluted share, on revenues of $160.7 million. For 2003, cash flow from operations increased 35% to $123.8 million from $91.5 million for 2002. The increase in net income and cash flow from operations from 2002 was primarily a result of higher production and higher commodity prices throughout the year.
•
We improved our financial flexibility and liquidity by negotiating an increased borrowing base under the existing credit facility from $220 million to $270 million. At December 31, 2003, we had $29 million outstanding on the borrowing base and $241 million available for funding of future capital requirements.
•
We improved our ability to access capital markets with the filing of a $400 million universal shelf registration statement on Form S-3. We currently have $216 million availability remaining under the registration statement.
•
We expanded the liquidity and public ownership of our common stock by facilitating the sale of common stock by J.P. Morgan and Warburg Pincus. On November 13, 2003, we priced a public offering of 8.0 million shares of our common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. We used all of the net proceeds to repurchase 6,866,643 shares of our common stock from J.P. Morgan and 2,193,357 shares from Warburg Pincus at a price of $19.3775 per share. The 9.06 million shares we purchased were retired upon repurchase. Our total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan
no longer beneficially owns any of our common stock and Warburg Pincus beneficially owns 24.5% of our common stock.
•
High-pressure air injection was implemented in a second area on the CCA properties in the Little Beaver area. We were able to negotiate the purchase of high-pressure air compression services from an offset operator. This allowed us to implement a project in Little Beaver unit, on the south end of the Cedar Creek Anticline, in less than one year. First injection began in Little Beaver phase one during December 2003 and phase one and phase two should be completed during 2004. Our independent reserve engineers, Miller and Lents, Ltd., booked 12.2 million barrels of oil reserves associated with high pressure air at year end 2003 at Little Beaver. High pressure air injection contributed to our FD&A cost during 2003.
Results of Operations
Comparison of 2003 to 2002
Set forth below is our comparison of operations during the year ended December 31, 2003 with the year ended December 31, 2002.
Revenues and Production. For the year ended December 31, 2003, revenues increased $59.4 million. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2003 and 2002, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit amounts):
Oil revenues increased $41.5 million in 2003 over 2002 as production increased 564 MBbls and our average realized price increased $4.38 per Bbl. The increase in production resulted from our successful development drilling program and uplift from the HPAI program. Oil revenues were reduced by $13.9 million in 2003 due to our hedging program. The hedging per Bbl reduction to our wellhead oil price of $2.10 represented a $1.06 per Bbl greater reduction than in 2002. This compares favorably with the
$4.96 increase in the average NYMEX price from 2002 to 2003 as we were able to realize additional upside due to a higher average ceiling on our 2003 hedges compared to NYMEX than in 2002. In addition, our oil wellhead revenue was reduced by $5.6 million and $2.0 million in 2003 and 2002, respectively, for the net profits interests payments made to others related to our CCA properties.
Natural gas revenues increased in 2003 by $17.9 million due to a 65% increase in the net wellhead price received along with increased production of 876 MMcf. The increase in net wellhead price received of $1.97 per Mcf resulted as the average NYMEX price increased $2.14 per Mcf over the same period. The natural gas production increase resulted from the Elm Grove acquisition during 2003. Averaging 7,984 Mcfe per day since its acquisition on July 31, 2003, the Elm Grove properties added 3,345 Mcfe per day to our average daily production for the full year.
For 2004, we anticipate increased production related to our budgeted $93 million capital drilling program and $34 million in HPAI projects. We also have an additional $13 million budgeted for leasehold and other general capital expenditures. The total capital budget for 2004 is $140 million.
Prices received for oil and natural gas production are largely based on current market prices, which are beyond our control. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects on $23.50 per Bbl and $3.75 per Mcf NYMEX prices to ensure a good rate of return to our shareholders without the benefit of escalating future commodity prices. If NYMEX prices trend downward below our base deck, we may reevaluate our capital projects. At these assumed prices, we have forecasted net hedge contract payments of approximately $0.9 million for oil and net receipts of $4.5 million for natural gas. However, these amounts will change directly with any change in the market price of oil and natural gas and with any change in our outstanding hedge positions. Additionally, we have anticipated net profits interests payments of $1.7 million for oil and $0.03 million for natural gas. These payments are highly dependent on the level of drilling in the CCA and commodity prices, and thus, any change in the level of drilling or market fluctuation in commodity prices will have a direct impact on the amount of payments we are required to make. If commodity prices are significantly lower than our forecasted prices of $23.50 for oil and $3.75 for natural gas, we will not have sufficient internally generated cash flow to fund the budgeted $93 million drilling program, $34 million in HPAI projects, and $13 million leasehold and other capital for 2004. In this case, we would have to borrow money under our existing revolving credit facility, seek capital markets, or curtail the capital program. If drilling is curtailed or ended, future cash flows could be materially negatively impacted.
Lease Operations Expense. Lease operations expense for the year ended December 31, 2003 increased by $7.2 million as compared to 2002. The increase in total lease operations expense resulted from the increase in volumes as a result of our 2003 drilling program, the Elm Grove acquisition and HPAI program. See “- Revenues and Production” above. On a per BOE basis, lease operations expense increased $0.52 primarily due to (1) full year results of our Paradox Basin properties, which had higher average per BOE lease operations expense of $9.04 for 2003 compared to our average of $4.67 per BOE, (2) the HPAI project on the CCA properties, and (3) lower production volumes from our Lodgepole properties, which have low operating costs.
For 2004, we anticipate an increase in total lease operations expense, as well as on a per BOE basis. We anticipate this increase due to a full year of production at our North Louisiana properties, as well as further implementation of the high-pressure air injection program. Also, the continued production decline of our Lodgepole properties, which have low per BOE operating costs, will continue to raise our lease operations expense on a per BOE basis. We have projected total lease operations expenses of approximately $46.5 million, or $5.56 per BOE, for 2004.
Production, Ad Valorem, and Severance Taxes. Production, ad valorem, and severance taxes for the year ended December 31, 2003 increased as compared to 2002 by approximately $6.4 million. The increase is a direct result of the increase in wellhead revenue. See “- Revenues and Production” above. As a
percentage of oil and natural gas revenues (excluding the effects of net profits and hedges), production, ad valorem, and severance taxes increased slightly from 9.3% to 9.4% from 2002 to 2003.
For 2004, total production, ad valorem, and severance taxes will depend in a large part on prevailing oil and natural gas prices. However, the production, ad valorem, and severance tax rate should remain relatively constant at an estimated 9.1% of wellhead revenues. However, if NYMEX prices continue to stay above $30 per barrel, we will temporarily lose production and severance tax incentives in Montana and North Dakota, which would cause our tax rates to increase in 2004.
Depletion, Depreciation, and Amortization (“DD&A”) Expense. Despite an increase in production, DD&A expense decreased by approximately $1.0 million in 2003. This decrease was due to the adoption of SFAS 143 on January 1, 2003, which resulted in a lower per BOE rate. As a result of the adoption of SFAS 143, we can no longer assume proceeds received for the salvage value of our equipment will offset plugging and abandonment costs, and thus are now required to deduct salvage value from the book value of equipment in calculating our depreciable base. This was the primary driver of the decrease in the average DD&A rate from $4.67 per BOE of production during 2002 to $4.13 per BOE in 2003.
We anticipate the total DD&A expense in 2004 will increase due to increased production resulting from the Elm Grove acquisition and our planned 2004 capital expenditures of $140 million. Assuming capital expenditures do not differ significantly from our budgeted amount, we expect our DD&A rate for 2004 to be approximately $4.60 per BOE. This per BOE increase from 2003 is primarily attributable to higher than historical FD&A costs for 2003. This rate could vary significantly based on actual capital expenditures, production rates, net profits interests, and any acquisition that closes in 2004. Additionally, changes in the market price for oil and natural gas could affect the level of our reserves. As the level of reserves change, the DD&A rate is inversely affected.
General and Administrative (“G&A”) Expense. G&A expense increased $2.5 million ($0.24 per BOE) to $8.7 million in 2003 (excluding non-cash stock based compensation of $0.6 million in 2003). The increase in G&A expense was a result of increased staffing levels used to manage our growing asset base and outside consulting services used in the evaluation of potential acquisitions.
We have forecast approximately $9.8 million for general and administrative expenses in 2004. This represents an increase of approximately $1.1 million from 2003. The increase is expected to result from the continued implementation of the HPAI projects, increased staffing, additional expenses related to compliance with the Sarbanes-Oxley Act of 2002 and the changes in listing requirements of The New York Stock Exchange.
Non-Cash Stock Based Compensation Expense. Non-cash stock based compensation expense increased from zero in 2002 to $0.6 million in 2003. This expense represents the amortization of deferred compensation, recorded in equity related to restricted stock granted under the 2000 Incentive Stock Plan. This amount is being amortized to expense over the vesting period of the restricted stock.
During 2002 and 2003, we issued 129,328 and 45,461 shares, respectively, of restricted stock to employees. Of these, 77,901 shares issued in 2002 and 45,461 shares issued in 2003 vest in equal installments on the third, fourth, and fifth anniversary of the date of the grant and depend only on continued employment for future issuance. These represent a fixed award per APB 25 and compensation expense will be recorded over the related service period. Of the remaining 51,427 shares issued in 2002, 34,464 remain outstanding at December 31, 2003. These were issued to two members of senior management and also vest in equal installments on the third, fourth, and fifth anniversary of the date of the grant. However, these shares not only depend on the passage of time and continued employment, but on certain performance measures for their future issuance. These represent a variable award under APB 25 and, thus, the full amount of compensation expense to be recorded for these shares will not be known until their eventual issuance.
Other Operating Expense. Other operating expense for the year ended December 31, 2003 increased as compared to 2002 by approximately $1.4 million. This amount primarily consists of 2003 severance payment obligations to former employees. The remaining amount relates to the inclusion of accretion
expense on our SFAS 143 future abandonment liability; and the abandonment in undeveloped leasehold costs.
For 2004, we anticipate other operating expense to be approximately $2.9 million.
Interest Expense. Interest expense for the year ended December 31, 2003 increased $3.8 million over 2002 due primarily to an increase in our weighted average interest rate from period to period, as well as an increase in debt outstanding related to our credit facility. We incurred additional debt in 2003 to fund the North Louisiana acquisition. The weighted average interest rate, net of hedges, for 2003 was 9.6% compared to 8.2% for 2002. This higher weighted average interest rate is the result of the issuance of $150 million aggregate principal amount of 8 3/8% senior subordinated notes in June 2002, which was the primary component of our total indebtedness during 2003, while the revolving credit facility with a lower floating rate was the primary component during the first half of 2002. In conjunction with the issuance of 8 3/8% notes in June 2002, we entered into an interest rate swap, which swaps fixed rates to floating, with the intent of lowering our effective interest payments. As this transaction does not qualify for hedge accounting, changes in its fair market value, as well as settlements, are not recorded in interest expense, but in ‘Derivative fair value (gain) loss’ on the Consolidated Statements of Operations. During 2003, a gain of $1.5 million related to this interest rate swap was recorded in ‘Derivative fair value (gain) loss’. See Note 11 to the accompanying consolidated financial statements.
The following table illustrates the components of interest expense for 2003 and 2002 (in thousands):
Derivative Fair Value Gain/Loss. The derivative fair value gain of $0.9 million in 2003 represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, settlements received on our fixed to floating interest rate swap, any commodity derivatives not designated as hedges, and changes in the mark-to-market value of our fixed to floating interest rate swap.
Currently, this line item on the Statement of Operations is primarily dependent on the futures price of oil, natural gas and LIBOR interest rates. This is due to the fact that the main components are the mark-to-market movement of and any settlements on our commodity derivative contracts not designated as hedges and our fixed to floating interest rate swap.
Income Tax Expense. Income tax expense for 2003 increased $13.5 million over 2002. This increase is due primarily to the $38.6 million increase in Income before Income Taxes from 2002 to 2003. Our effective income tax rate, prior to adjusting for Section 43 credits, remained at a constant 38% for both 2002 and 2003. However, during 2003, we generated $2.1 million in Section 43 credits, as compared to $1.1 million of Section 43 credits generated in 2002. This increase resulted in an effective income tax rate of 36.5% in 2003, a decrease of 1% from our 2002 effective rate of 37.5%.
Comparison of 2002 to 2001
Set forth below is our comparison of operations during the year ended December 31, 2002 with the year ended December 31, 2001.
Revenues and Production. For the year ended December 31, 2002, revenues increased $24.8 million. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2002 and 2001, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit amounts):
Oil revenues increased $29.1 million in 2002 over 2001 primarily due to an increase in oil volumes, while the net wellhead price received remained relatively flat. Oil volumes increased 1,102 MBbls from 2001 to 2002 due to the Central Permian and Paradox Basin acquisitions, as well as increased production from our successful development drilling program. Wellhead oil revenues were reduced by $2.0 million and $2.7 million in 2002 and 2001, respectively, for the net profits interests payments held by others in the CCA. Total oil revenues were further increased by a decrease in hedge payments, which were $2.7 million lower.
Natural gas revenues decreased in 2002 by $4.3 million due to a 28% decrease in the net wellhead price received, from $4.21 in 2001 to $3.03 in 2002, with essentially flat production. This price decline is consistent with the NYMEX decline from $4.06 to $3.36 over the same period. We recovered a portion of the natural gas price decline through our hedges, which generated net receipts of $1.0 million in 2002 versus net payments of $3.9 million in 2001. These hedging receipts are a direct result of the decrease in the average NYMEX price for natural gas.
Lease Operations Expense. Lease operations expense for the year ended December 31, 2002 increased as compared to 2001 by $5.5 million. The increase in lease operations expenses resulted from the increase in volumes as a result of our 2002 Central Permian and Paradox Basin acquisitions and our successful drilling program. See “- Revenues and Production” above. On a per BOE basis, lease operations expenses increased from $4.00 in 2001 to $4.15 in 2002 primarily due to higher per BOE lifting costs for our 2002 acquisitions.
Production, Ad Valorem, and Severance Taxes. Production, ad valorem, and severance taxes for the year ended December 31, 2002 increased as compared to 2001 by approximately $1.8 million. The increase is a direct result of the increase in wellhead revenue. See “- Revenues and Production” above. As a
percentage of oil and natural gas revenues (excluding the effects of net profits and hedges), production, ad valorem, and severance taxes increased slightly from 9.1% to 9.3% from 2001 to 2002.
Depletion, Depreciation, and Amortization (“DD&A”) Expense. DD&A expense increased by approximately $2.8 million in 2002. This increase was due to a 1.1 MMBOE increase in production volumes, partially offset by a decrease in the DD&A rate per BOE. See “- Revenues and Production” above. The average DD&A rate decreased from $5.05 per BOE of production during 2001 to $4.67 per BOE in 2002. The increase in volumes caused a $5.6 million increase in related DD&A expense, while the decrease in the DD&A rate caused a $2.8 million decrease. The decrease is attributable to upward reserve revisions due to higher prices.
General and Administrative (“G&A”) Expense. G&A expense increased $1.1 million in 2002 (excluding non-cash stock based compensation of $9.6 million in 2001). The increase in G&A resulted from the additional staff necessary after the Permian and Paradox Basin acquisitions to manage, expand, and exploit our growing asset base. On a per BOE basis, G&A expense remained relatively flat at $0.83 during 2002 as compared to $0.80 during 2001.
Other Operating Expense. Other operating expense for the year ended December 31, 2002 increased as compared to 2001 by approximately $1.1 million. This amount primarily consists of 2001 severance payment obligations to former employees, as well as transportation costs, namely pipeline fees paid to third parties, geological and geophysical expenses, and delay rentals. The increase is due to higher transportation costs and geological and geophysical expenses in 2002, which more than offset the lack of severance payments in 2002.
Interest Expense. Interest expense for the year ended December 31, 2002 increased $6.3 million over 2001. The increase in interest expense is primarily due to increased levels of debt, amortization of hedge loss (see below), and a higher weighted average interest rate in 2002 as compared to 2001. On June 25, 2002, we issued $150.0 million in 8 3/8% senior subordinated notes, and used most of the proceeds to repay all amounts outstanding under the previous credit facility and entered into a new revolving credit facility. See “- Capital Commitments, Capital Resources and Liquidity” on page 31. For 2002, the weighted average debt balance was $149.7 million, compared with $89.3 million for 2001. Additionally, the weighted average interest rate, including hedges, in 2002 was 8.2%, while it was 6.8% in 2001. The higher weighted average interest rate is due to a higher fixed rate on the 8 3/8% notes as compared to the floating rate debt outstanding previously.
At the time the previous credit facility was terminated, we had three interest rate swaps outstanding, with a notional amount of $30.0 million each, which swapped LIBOR-based floating rates for fixed rates. According to the provisions of SFAS 133, these no longer qualified for hedge accounting. The unrealized loss of $3.8 million at June 25, 2002, which was recognized in accumulated other comprehensive income, is being amortized to interest expense over the original life of the swaps. We amortized $1.6 million of this loss to interest expense during 2002.
The following table illustrates the components of interest expense for 2002 and 2001 (in thousands):
Non-Cash Stock Based Compensation Expense. Non-cash stock based compensation expense decreased from $9.6 million for 2001 to zero in 2002. This non-cash stock based compensation expense is associated with the purchase by our management stockholders of Class A common stock under our management stock plan adopted in August 1998 and was recorded as compensation in accordance with variable plan accounting under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”). The $9.6 million of non-cash compensation expense recorded in the first quarter of 2001 represents the final amount of expense to be recorded related to the Class A common stock.
Derivative Fair Value Gain/Loss. The derivative fair value gain of $0.9 million in 2002 represents the ineffective portion of the mark-to-market loss on our derivative hedging instruments, as well as the mark-to-market loss on our two short puts outstanding at December 31, 2002 and our interest rate swap settlements subsequent to the issuance of the senior subordinated notes on June 25, 2002.
Bad Debt Expense. On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Prior to this date, we had entered into oil and natural gas hedging contracts with Enron, many of which were set to expire at December 31, 2001; however, others related to 2002 and 2003. As a result of the Chapter 11 bankruptcy declaration and pursuant to the terms of our contract with Enron, we terminated all outstanding oil and natural gas derivative contracts with Enron as of December 12, 2001. According to the terms of the contract, Enron is liable to us for the mark-to-market value of all contracts outstanding on that date, which totaled $6.6 million. Additionally, Enron failed to make timely payment of $0.4 million in 2001 hedge settlements. Both of these amounts remained outstanding as of December 31, 2001. Due to the uncertainty of future collection of any or all of the amounts owed to us by Enron, for the year ended December 31, 2001, we have recorded a charge to bad debt expense for the full amount of the receivable, $7.0 million, and recorded a related allowance on the receivable of $7.0 million.
At the time of termination, the market price of our commodity contracts with Enron exceeded their amortized cost on our balance sheet, giving rise to a gain. In accordance with the provisions of SFAS 133, this gain was recorded in other comprehensive income until such time as the original hedged production affected income. As a result, at December 31, 2001, we had $4.8 million in gross unrecognized gains in other comprehensive income that were reversed into earnings during 2002 and 2003. The following table illustrates the amortization of this amount to revenue (in thousands):
Impairment of Oil and Natural Gas Properties. Throughout 2001, futures prices for oil and natural gas continued to decline from their December 31, 2000 levels. The SEC price case used for our 2000 reserve estimate was $26.80 per Bbl and $9.77 per Mcf dropping to $19.84 per Bbl and $2.57 per Mcf for the 2001 estimate. Although the SEC price case does not necessarily coincide with management’s estimates of future prices, this indicated the need to assess our oil and natural gas properties for any possible impairment. Thus, we compared the undiscounted future cash flows for each of our oil and natural gas properties to their net book value, which indicated the need for an impairment charge on certain properties. We then compared the net book value of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $2.6 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes discounted back to a present value using a rate commensurate with the risks inherent in the industry.
We performed a similar review at December 31, 2002 and determined no impairment charge was necessary.
Description of Critical Accounting Estimates
Oil and Natural Gas Properties
Successful Efforts Method. We utilize the successful efforts method of accounting for our oil and natural gas properties as opposed to the full cost method. In general, we believe that the successful efforts method of accounting for oil and natural gas would not result in materially different operating results as we do not currently maintain an active exploratory drilling program. Under the successful efforts method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. To date, our exploration efforts have been minimal. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in our consolidated financial statements.
Oil and Natural Gas Reserves. Assumptions used by the independent reserve engineers in calculating reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Furthermore, prices and costs will not remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property’s fair value.
Impairment. Impairments of proved oil and natural gas properties are directly affected by our reserve estimates. We are required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Each part of this calculation is subject to a large degree of management judgment, including the determination of property’s reserves, amount and timing of future cash flows, and fair value.
Depletion, Depreciation, and Amortization (“DD&A”). DD&A expense is directly affected by our reserve estimates. Any change in reserves directly impacts the amount of DD&A expense that we recognize in a given period. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. Additionally, the Miller & Lents, Ltd., our independent reserve engineers estimate our reserves once a year at December 31.
Net Profits Interests
A major portion of our acreage position in the Cedar Creek Anticline is subject to net profits interests (“NPI”) ranging from 1% to 50%. The holders of these net profits interests are entitled to receive a fixed percentage of the cash flow remaining after specified costs have been deducted from net revenues. The net profits calculations are contractually defined, but in general, net profits are determined after considering operating expense, overhead expense, interest expense, and drilling costs. The amounts of reserves and production calculated to be attributable to these net profits interests are deducted from our reserves and production data, and our revenues are reported net of NPI payments. The reserves and production that are attributed to the NPIs are calculated by dividing estimated future NPI payments (in the case of reserves) or prior period actual NPI payments (in the case of production) by the commodity prices current at the determination date. Fluctuations in commodity prices and the levels of development activities in the CCA from period to period will impact the reserves and production attributed to the NPIs and will have an inverse effect on our reported reserves and production. Based largely on higher commodity prices, we expect the net profit interest to be higher in the year 2004 and possibly beyond, which directly impacts our revenues, production, reserves, and earnings.
Revenue Recognition
Revenues are recognized for our share of jointly owned properties as oil and natural gas is produced and sold, net of royalties and net profits interest payments. Natural gas revenues are also reduced by any processing and other fees paid except for transportation costs paid to third parties which are recorded as expense. Revenues are recorded using the sales method of accounting whereby revenue is recognized as natural gas is sold by us rather than as our working interest share of production. Royalties, net profits interests, and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, we estimate and record the expected sales volumes and values for those properties. We also do not recognize revenue for the production in tanks or pipelines that has not been delivered to the purchaser yet. Our net oil inventories in pipelines were 46,622 Bbls and 104,954 Bbls at December 31, 2003 and 2002, respectively. Natural gas imbalances under-delivered to us at December 31, 2003 and December 31, 2002, were 446,000 MMBTU and 510,000 MMBTU, respectively.
Income Taxes
Section 43 Credits. Section 43 of the Internal Revenue Code (“Code”) allows a 15 percent tax credit for certain enhanced oil recovery project costs incurred in the United States. We believe project costs incurred related to our HPAI tertiary recovery project on the CCA qualify under the provisions of the Code and, therefore, we have reduced income tax expense by 15 percent of project costs incurred to date. The tax basis for the properties (and related intangible drilling cost deductions and future depreciation deductions) is reduced by the amount of the enhanced oil recovery tax credit. In order to qualify for the credits a project must meet all of the following requirements:
1. The project involves the application of one or more qualified tertiary recovery methods that is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered;
2. The project is located within the United States;
3. The first injection of liquids, gases, or other matter for the project occurs after December 31, 1990; and
4. The project is certified by a petroleum engineer.
According to the Code, the costs that will qualify for the credit when paid or incurred in connection with a qualifying enhanced oil recovery project include:
1. Tangible Property. Any amount paid for tangible property that is an integral part of a qualified enhanced oil recovery project, and with respect to which depreciation is allowable.
2. Intangible Drilling and Development Costs. Intangible drilling cost with respect to which the taxpayer may make an intangible drilling costs deduction election under Code Sec. 263(c).
3. Qualified Tertiary Injectant Expenses. Any qualified tertiary injectant expenses for which a deduction is allowable under any Code section.
If our federal income tax returns are reviewed by the Internal Revenue Service (the “IRS”), the IRS could disagree with our decision and disallow a portion of the credit. While we believe our HPAI project qualifies for the tax credit and that our accounting and tracking of the costs related to project are accurate, should the IRS disagree with our position, we would be required to record additional income tax expense to the extent tax credits have been previously recognized.
Stock-based Compensation
Employee stock options and restricted stock awards are accounted for under the provisions of Accounting Principles Board Opinion No. 25 (“APB 25”), “Accounting for Stock Issued to Employees.” Accordingly, no compensation is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. If compensation expense for the stock based awards had been determined using the provisions of SFAS 123, our net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share amounts):
Hedging and Related Activities
We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our crude oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts executed with large financial institutions. We also use derivative instruments in the form of interest rate swaps, which hedge our risk related to interest rate fluctuation.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities.” This standard requires us to recognize all of our derivative and hedging instruments in our statements of financial position as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the
change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. Most of our derivative financial instruments qualify for hedge accounting. In accordance with the provisions of SFAS 133, cash flow hedges are marked-to-market through comprehensive income each quarter.
Currently, all of our derivative financial instruments that are designated as hedges are designated as cash flow hedges. These instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in ‘Other Comprehensive Income’ in Stockholders’ Equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the gain or loss is recognized as ‘Derivative fair value (gain) loss’ in the Consolidated Statements of Operations immediately. While management does not anticipate changing the designation of any of our current derivative contracts as hedges, factors beyond our control can preclude the use of hedge accounting. One example would be variability in the NYMEX price for oil or natural gas, upon which many of our commodity derivative contracts are based, that does not coincide with changes in the spot price for oil and natural gas that we are paid. Another example would be if the counterparty to a derivative contract was deemed no longer creditworthy and non-performance under the terms of the contract was likely. To the extent our derivative contracts are not designated as hedges, high earnings volatility can result, as any future changes in the market value of the contract would then be marked-to-market through earnings.
Capital Commitments, Capital Resources and Liquidity
Capital Commitments. Our primary needs for cash are as follows:
•
Development and exploitation of our existing oil and natural gas properties
•
High-pressure air injection programs on our CCA properties
•
Acquisitions of oil and natural gas properties
•
Leasehold and acreage costs
•
Other general property and equipment
•
Funding of necessary working capital
•
Payment of contractual obligations
Development and Exploitation. Our capital expenditures for conventional development and exploitation during the years ended December 31, 2003 and 2002 totaled $86.1 million and $73.7 million, respectively.
For 2004, we expect to invest $93 million in development and exploitation. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. For comparability and accountability, we take a constant approach to budgeting commodity prices. We analyze our inventory of capital projects based on $23.50 per Bbl and $3.75 per Mcf NYMEX prices to ensure a rate of return to our shareholders without the benefit of escalating future commodity prices. If NYMEX prices trend downward below our base deck, we may reevaluate capital projects and may adjust the capital budgeted for development and exploitation investments accordingly.
High-Pressure Air Injection. Our capital expenditures for high-pressure air injection during the years ended December 31, 2003 and 2002 totaled $12.9 million and $6.6 million, respectively. In 2003, we began implementing our second HPAI program in the Little Beaver unit of the CCA and began injecting air in the reservoir in December 2003. We expect to have the Little Beaver unit fully implemented by the first quarter of 2004. The Little Beaver unit project was taken from concept to implementation in less than
9 months. We successfully negotiated a contract from a third party to supply the air compression services to Little Beaver, which reduced the up front capital requirements for the Little Beaver unit project. In 2002, we began a pilot program to begin injecting air into the Red River U4 reservoir in a portion of the Pennel Unit of the CCA. Because of positive results, we are planning to expand the project in the Pennel unit of the CCA with a $25.2 million expansion of the project which we expect to complete by early 2005. We believe that the HPAI program will generate a higher rate of return than other tertiary processes and can be applied throughout the CCA. The zone of our initial focus, the Red River U4 zone, is the same zone where HPAI has been successfully implemented by other operators in adjacent areas and on the Pennel unit of the CCA. Response from HPAI investments is not expected until ten to eighteen months from the time of first injection.
For 2004, we expect to invest $34 million in high-pressure air injection. We have based our 2004 forecasts on the assumptions of $23.50 per Bbl and $3.75 per Mcf NYMEX prices. See “- Development and Exploitation” above regarding our approach to budgeting commodity prices.
Acquisitions. Our capital expenditures for oil and natural gas acquisitions during the years ended December 31, 2003 and 2002 totaled $54.6 million and $78.5 million, respectively. In 2003, we completed an acquisition of interests in natural gas properties in North Louisiana. The properties are located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections. The production and reserves of the properties are substantially all natural gas. On January 1, 2002, we completed the Central Permian acquisition from Conoco for approximately $50.1 million. During the second quarter of 2002, we closed a second, follow-on acquisition of additional working interest for $8.3 million. The Central Permian properties increased our operational presence in West Texas. On August 29, 2002 we acquired an interest in oil and natural gas properties in southeast Utah’s Paradox Basin.
We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio. For the year ended 2003, we evaluated over $1 billion of potential acquisitions. We do not budget for acquisitions but we will continue to evaluate acquisition opportunities as they arise in 2004 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value.
Our current $140 million capital budget for 2004 does not include any funds for the development and exploitation of oil and natural gas properties that we may acquire during 2004. Our practice is to review our capital budget following a significant acquisition. We are currently undertaking such a review in connection with the Cortez transaction.
Leasehold and Acreage Costs. Our capital expenditures for leasehold and acreage costs during the years ended December 31, 2003 and 2002 totaled $0.1 million and $0.4 million, respectively.
For 2004, we expect to invest $12 million for leasehold and acreage costs. Compared to historical expenditures for leasehold and acreage, 2004 will be a significant increase in capital expenditures. We plan to actively pursue leases and acreage in our core areas that we are currently operating oil and natural gas properties. These investments are not expected to result in oil and natural gas production in 2004.
Other General Property and Equipment. Our capital expenditures for other general property and equipment during the years ended December 31, 2003 and 2002 totaled $1.5 million and $0.7 million, respectively. Capital expenditures for other general property and equipment include corporate leasehold improvements, computers, software, telecommunications equipment, field trucks, and field rental equipment.
For 2004, we expect to invest $0.8 million in other general property and equipment.
Working Capital. At December 31, 2003, our working capital was $(0.1) million while at December 31, 2002 working capital was $12.5 million, a decrease of $12.6 million. The decrease is primarily attributable to cash and cash equivalents. Excluding the decrease in cash of $12.6 million, working capital was essentially flat from 2002 to 2003. In order to minimize our interest expense, we use
excess cash reserves to pay down any amounts outstanding under our revolving credit facility. However, at the end of 2002, due to the margin maintenance requirements with our commodity derivative counterparties and the high commodity price environment, we maintained cash reserves on hand to satisfy any margin calls as they arose. Thus, we held a much higher cash and cash equivalents balance at December 31, 2002 than would otherwise be held. This resulted in the decrease in working capital from December 31, 2002 to December 31, 2003. Currently, as of March 3, 2004, we have $4.5 million posted related to our derivatives margin account.
For 2004, we expect working capital to remain relatively flat to 2003. We anticipate cash reserves to be close to zero as we use any excess cash to fund capital obligations and any additional excess cash would be used to pay down our existing credit facility. We do not plan to pay cash dividends in the foreseeable future. The overall 2004 commodity prices for oil and natural gas will be the largest variable driving the different components of working capital. Our operating cash flow is determined in a large part by commodity prices. Assuming moderate to high commodity prices, our operating cash flow should remain positive for the foreseeable future. We have budgeted capital expenditures of approximately $140.0 million for 2004. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. We plan to finance our ongoing expenditures using internally generated cash flow, available cash, and our existing credit agreement.
Contractual Obligations. The following table illustrates our contractual obligations and commercial commitments outstanding at December 31, 2003 (in thousands):
(1)
Amounts included in the table above include both principal and projected interest payments. See information presented in “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt.
(2)
Amounts included in the table above include both principal and projected interest payments. See “Note 6. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt. Giving effect to the Cortez acquisition, the pro-forma amount outstanding under our revolving credit facility as of December 31, 2003 would be approximately $152.0 million.
(3)
Derivative obligations represent liabilities for derivatives that were valued as of December 31, 2003. The ultimate settlement amounts of the remaining portions of our derivative obligations are unknown because they are subject to continuing market risk. See “Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Hedging Policy. We have adopted a formal hedging policy. The purpose of our hedging program is to mitigate the negative effects of declining commodity prices on our business. The hedging policy is set by the President with input from the Chief Executive Officer and the Chief Financial Officer. We plan to continue in the normal course of business to hedge our exposure to fluctuating commodity prices. The volumes we have capped or swapped will not exceed 75% of our anticipated production from proved producing reserves. Under our hedging policy, we do not enter into derivatives for speculative purposes. However, not all of our derivatives qualify for hedge accounting and in some instances management has determined it is more cost effective not to designate certain derivatives as hedges.
Counterparties. Our counterparties to hedging contracts include: BNP Paribas; Deutsche Bank; Koch; Morgan Stanley; Mitsui & Co; Shell Trading; Credit Lyonnais; J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. At December 31, 2003 approximately 35%, 23%, 20%, and 16% of estimated oil production hedged is committed to Morgan Stanley, J. Aron & Company, Deutsche Bank, and Credit Lyonnais, respectively. Approximately 42%, 33%, and 25% of our hedged gas production is contracted with BNP Paribas, J. Aron & Company, and Morgan Stanley, respectively. Performance on all of J. Aron & Company’s contracts with us is guaranteed by their parent, Goldman, Sachs & Co. We feel the credit-worthiness of our current counterparties is sound and we do not anticipate any non-performance of contractual obligations. As long as each counterparty maintains an investment grade credit rating, pursuant to our hedging contracts, no collateral is required.
In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating separately each financial transaction between our counterparty and us, the master netting agreement enables our counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement benefits us in three ways. First, the netting of the value of all trades reduces the requirements of daily collateral posting by us. Second, default by counterparty under one financial trade can trigger rights for us to terminate all financial trades with such counterparty. Third, netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.
Commodity Price Sensitivity. The tables in this section provide information about derivative financial instruments to which we were a party as of December 31, 2003 that are sensitive to changes in oil and natural gas commodity prices.
We hedge commodity price risk with swap contracts, put contracts, and collar contracts. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, we occasionally we sell short put contracts with a strike price well below the floor price of the collar. These short put contracts do not qualify for hedge accounting under SFAS 133, and accordingly, the mark-to-market change in the value of these contracts is recorded as fair value gain/loss in the statements of operations. Thus, not all of our derivatives qualify for hedge accounting and in some instances management has determined it is more cost effective not to designate certain derivatives as hedges. The unrealized mark-to-market loss on our outstanding commodity derivatives at December 31, 2003 was approximately $(16.0) million. The fair market value of our oil derivative contracts was $(7.1) million and the fair market value of our natural gas derivative contracts was $(0.6) million.
Oil Derivative Contracts at December 31, 2003
Natural Gas Derivative Contracts at December 31, 2003
Subsequent to December 31, 2003, we entered into several additional oil and natural gas derivative contracts. The tables below summarize the terms of the contracts entered into from January 1, 2004 through March 4, 2004:
Additional Oil Derivative Contracts at March 4, 2004
Additional Natural Gas Derivative Contracts at March 4, 2004
Interest Rate Sensitivity. At December 31, 2003, we had total long-term debt of $179.0 million. Of this amount, $150.0 million bears interest at a fixed rate of 8 3/8%. The remaining outstanding long-term debt balance of $29.0 million is under our credit agreement and is subject to floating market rates of interest. Borrowings under the credit agreement bear interest at a fluctuating rate that is linked to LIBOR. As of December 31, 2003, we had one outstanding interest rate swap. This swap does not qualify for hedge accounting as it swaps fixed interest rate for a floating interest rate tied to LIBOR. The following table summarizes the terms of this swap:
Interest Rate Derivative Contract at December 31, 2003
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and this Report:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.
Bbl/ D. One stock tank barrel of oil or other liquid hydrocarbons per day.
BOE. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
BOE/ D. One barrel of oil equivalent per day, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Delay Rentals. Fees paid to the lessor of the oil and natural gas lease during the primary term of the lease prior to the commencement of production from a well.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well. A well drilled within or in close proximity to an area of known production targeting existing reservoirs.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Finding, Development, and Acquisition (“FD&A”) Costs. Capital costs incurred in the finding, development, acquisition, exploitation, improved recovery, and revisions of proved oil and natural gas reserves, excluding non-cash asset retirement obligations.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.
High-Pressure Air Injection (“HPAI”). High-pressure air injection involves utilizing compressors to inject air into previously produced oil and natural gas formations in order to displace remaining resident hydrocarbons and force them under pressure to a common lifting point for production.
Horizontal Drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
Lease Operations Expense. All direct and indirect costs of producing oil and natural gas after completion of drilling and before removal of production from the property. Such costs include labor, superintendence, supplies, repairs, maintenance, and direct overhead charges.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent, calculated by converting gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
Mcf. One thousand cubic feet of natural gas.
Mcf/ D. One thousand cubic feet of natural gas per day.
Mcfe. One thousand cubic feet of natural gas equivalent, calculated by converting oil to natural gas equivalent at a ratio of one Bbl of oil to six Mcf.
MMBOE. One million barrels of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
MMBtu. One million British thermal units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
Net Acres or Net Wells. Gross acres or wells multiplied, as the case may be, by the percentage working interest owned by us.
Net Production. Production that is owned by us less royalties and production due others.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil or condensate.
Operating Income. Gross oil and natural gas revenue less applicable production taxes and lease operating expense.
Operator. The individual or company responsible for the exploration, exploitation, and production of an oil or natural gas well or lease.
Present Value of Future Net Revenues or Present Value or PV-10. The pretax present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depletion, depreciation, and amortization, and discounted using an annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on acreage yet to be drilled for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production. Proved undeveloped reserves include unrealized production response from fluid injection and other improved recovery techniques where such techniques have been proved effective by actual tests in the area and in the same reservoir.
Reserve-To-Production Index or R/ P Index. An estimate expressed in years, of the total estimated proved reserves attributable to a producing property divided by production from the property for the 12 months preceding the date as of which the proved reserves were estimated.
Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized Measure. Future cash inflows from proved oil and natural gas reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or natural gasses are used as the injectant. HPAI is a form of tertiary recovery.
Unit. A specifically defined area within which acreage is treated as a single consolidated lease for operations and for allocations of costs and benefits without regard to ownership of the acreage. Units are established for the purpose of recovering oil and natural gas from specified zones or formations.
Waterflood. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
Item 8.
Item 8.
Financial Statements and Supplementary Data
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders of Encore Acquisition Company:
We have audited the accompanying consolidated balance sheets of Encore Acquisition Company and subsidiaries (“the Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of Encore Acquisition Company as of December 31, 2001, and for the year then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated March 1, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Encore Acquisition Company and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
/s/ ERNST & YOUNG LLP
Fort Worth, Texas
February 6, 2004
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of Encore Acquisition Company:
We have audited the accompanying consolidated balance sheets of Encore Acquisition Company (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Encore Acquisition Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivatives.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 1, 2002
Subsequent to the completion of the audit of the Company’s 2001 financial statements, Arthur Andersen LLP was convicted of obstruction of justice charges relating to a federal investigation of Enron Corporation and ceased operations as a public accounting firm. Accordingly, the report of independent public accountants included above is a copy of a report previously issued by Arthur Andersen. Arthur Andersen has not reissued its report for inclusion in this document.
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Formation of the Company and Basis of Presentation
Encore Acquisition Company (the “Company”), a Delaware Corporation, is an independent (non-integrated) oil and natural gas company in the United States. We were organized in April 1998 and are engaged in the acquisition, development, exploitation, and production of North American oil and natural gas reserves. Our oil and natural gas reserves are concentrated in fields located in the Williston Basin of Montana and North Dakota, the Permian Basin of Texas and New Mexico, the Anadarko Basin of Oklahoma, the Powder River Basin of Montana, the Paradox Basin of Utah, and the North Louisiana Salt Basin.
2.
Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of all subsidiaries in which we hold a controlling interest. All material intercompany balances and transactions are eliminated.
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less. On a bank-by-bank basis, cash accounts that are overdrawn are reclassified to current liabilities and any change in cash overdrafts is shown as a financing activity in the consolidated statements of cash flows.
Inventories
Inventories are comprised principally of materials and supplies, which are stated at the lower of cost (determined on an average basis) or market, and oil in pipelines. Oil produced at the lease which resides unsold in pipelines is carried at an amount equal to its operating costs to produce.
Oil and Natural Gas Properties
We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in the Company’s consolidated financial statements. Natural gas volumes are converted to equivalent barrels at the rate of six Mcf to one barrel. See Note 2, “New Accounting Standards,” on page 58 for a discussion of Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which the Company adopted as of January 1, 2003.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company is required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Any impairment charge incurred is expensed reduces our recorded basis in the asset.
The costs of retired, sold, or abandoned properties that constitute part of an amortization base are charged or credited, net of proceeds received, to the accumulated depletion, depreciation, and amortization reserve. Gains or losses from the disposal of other properties are recognized in the current period.
Additionally, the Company’s independent reserve engineers estimate our reserves once a year at December 31. This results in a new DD&A rate which the Company uses for the preceding fourth quarter and, to the extent no other reserve estimates change materially, the subsequent three quarters of the following year.
Stock-based Compensation
Employee stock options and restricted stock awards are accounted for under the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Accordingly, no compensation is recorded for stock options that are granted to employees or non-employee directors with an exercise price equal to or above the common stock price on the grant date. However, expense is recorded related to restricted stock granted to employees. If compensation expense for the stock based awards had been determined using the provisions of Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), the Company’s net income and net income per share would have been adjusted to the pro forma amounts indicated below (in thousands, except per share amounts):
Segment Reporting
The Company has only one operating segment, the development and exploitation of oil and natural gas reserves. Additionally, all of our assets are located in the United States and all of our oil and natural gas revenues are derived from customers located in the United States.
For 2003, 28%, 26%, and 11% of total oil and natural gas production was sold to ConocoPhillips, Shell, and Eighty-Eight Oil, respectively. In 2002, ConAgra and Equiva Trading Company (a joint venture between Shell and Texaco) accounted for 16% and 10% of total oil and natural gas sales, respectively. For 2001, 25%, 17%, and 11% of total oil and natural gas production was sold to ConAgra, Equiva Trading Company and EOTT Energy Co., respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income Taxes
Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Valuation allowances are established when necessary to reduce deferred tax assets to amounts expected to be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
Revenue Recognition
Revenues are recognized for Encore’s share of jointly owned properties as oil and natural gas is produced and sold, net of royalties and net profits interest payments. Revenues are also reduced by any processing and other fees paid except for transportation costs paid to third parties which are recorded as expense. Natural gas revenues are recorded using the sales method of accounting whereby revenue is recognized as natural gas is sold by the Company rather than as the Company’s working interest share of production. Royalties, net profits interests, and severance taxes are paid based upon the actual price received from the sales. To the extent actual quantities and values of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, we estimate and record the expected sales volumes and values for those properties. The Company also does not recognize revenue for the production in tanks or pipelines that has not been delivered to the purchaser yet. Encore’s net oil inventories in pipelines were 46,622 Bbls and 104,954 Bbls at December 31, 2003 and 2002, respectively. Natural gas imbalances under-delivered to Encore at December 31, 2003 and December 31, 2002, were 446,000 MMBTU and 510,000 MMBTU, respectively.
Shipping Costs
Shipping costs in the form of pipeline fees paid to third parties are incurred to move oil and natural gas production from certain properties to a different market location for ultimate sale. These costs are included in other operating expense in our statements of operations.
Hedging and Related Activities
We use various financial instruments for non-trading purposes to manage and reduce price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts with large financial institutions.
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities”. This standard requires us to recognize all of our derivative financial instruments in our consolidated balance sheets as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows of the hedged item. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The impact of adopting SFAS 133 on January 1, 2001 was to record the fair value of our derivatives as a reduction in assets of $1.1 million and as a
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
liability in the amount of $24.4 million. Additionally, we recorded a reduction in earnings as the cumulative effect of an accounting change of $0.9 million (net of taxes of $0.5 million) and a decrease to stockholders’ equity for other comprehensive income in the amount of $14.9 million (net of deferred taxes of $9.1 million).
Currently, all of our derivative financial instruments that are designated as hedges are designated as cash flow hedges. These instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the mark-to-market gain or loss on these derivative instruments is recorded in other comprehensive income in stockholders’ equity and reclassified into earnings in the same period in which the hedged transaction affects earnings. Any ineffective portion of the mark-to-market gain or loss is recognized into earnings immediately.
Comprehensive Income
Comprehensive income includes net income and other comprehensive income, which includes, effective January 1, 2001, unrealized gains and losses on derivative financial instruments. Encore chooses to show yearly comprehensive income as part of its consolidated statement of stockholders’ equity.
Use of Estimates
Preparing financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses reported. Actual results could differ materially from those estimates.
Estimates made in preparing these consolidated financial statements include the Company’s estimated proved oil and natural gas reserve volumes used in calculating depletion, depreciation, and amortization expense; the estimated future cash flows and fair value of our properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating the Company’s asset retirement obligations. See “Note 4. Commitments and Contingencies - Asset Retirement Obligations.” Future changes in the assumptions used could have a significant impact on reported results in future periods.
New Accounting Standards
Statements of Financial Accounting Standards No. 141, “Business Combinations” (“SFAS 141”) and No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) were issued in July 2001. SFAS 141 requires that all business combinations entered into subsequent to June 30, 2001 be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill’s impairment at least annually in accordance with the provisions of SFAS 142 and that intangible assets other than goodwill be amortized over their useful lives.
Currently, the Emerging Issues Task Force staff are engaged in discussions on the issue of whether SFAS 141 and SFAS 142 which were effective June 30, 2001, called for mineral rights held under a lease or other contractual arrangement to be classified on the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, oil and gas companies, including Encore, have included these costs with all other oil and natural gas property costs in Property, Plant, and Equipment on the consolidated balance sheet.
In the event this interpretation is adopted, a substantial portion of the acquisition costs of oil and natural gas properties would be required to be classified on the balance sheet as an intangible asset. The
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Company believes this interpretation would not have a material effect on our results of operations for the periods presented or in the future as these intangible assets would be depleted using the units of production method in a manner consistent with the method currently used to calculate depletion, depreciation, and amortization expense on these assets.
At December 31, 2003, the Company had $0.9 million of undeveloped leasehold costs and $291.5 million of developed leasehold costs (net of accumulated depletion) that would be reclassified as “Intangible developed and undeveloped leasehold costs” if the Company were to apply the interpretation as currently discussed.
In August 2001, the FASB issued SFAS 143, which the Company adopted as of January 1, 2003. This statement requires us to record a liability in the period in which an asset retirement obligation (“ARO”) is incurred. Also, upon initial recognition of the liability, we must capitalize additional asset cost equal to the amount of the liability. In addition to any obligations that arise after the effective date of SFAS 143, upon initial adoption we must recognize (1) a liability for any existing AROs, (2) capitalized cost related to the liability, and (3) accumulated depletion, depreciation, and amortization on that capitalized cost.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $4.0 million increase in the carrying values of proved properties, (ii) a $2.1 million decrease in accumulated depletion, depreciation, and amortization, and (iii) a $5.2 million increase in other non-current liabilities, and (iv) a gain of $0.9 million, net of tax, as a cumulative effect of accounting change on January 1, 2003. The Company does not include a market risk premium in its risk estimates as the effect would not be material.
The following table shows net income and basic and diluted net income per common share as reported, as well as pro forma amounts as if the Company had adopted SFAS 143 prior to January 1, 2001 (in thousands, except per common share amounts):
In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), which is effective for financial statements issued for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. SFAS 144 requires that long-lived assets to be disposed of by sale be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS 144 broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The Company adopted SFAS No. 144 effective January 1, 2002. The Company’s adoption of this statement has not had a material effect on its financial position or results of operations.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” Under Statement 4, all gains and losses from extinguishment of debt were required to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. This Statement eliminates Statement 4 and, thus, the exception to applying Opinion 30 to all gains and losses related to extinguishments of debt. As a result, gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in Opinion 30. Applying the provisions of Opinion 30 will distinguish transactions that are part of an entity’s recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. This statement is effective for Encore beginning January 1, 2003, at which time the extraordinary loss on extinguishment of debt of $0.9 million recorded in the second quarter of 2002 was reclassified to operating income.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. 123” (“SFAS 148”). This Statement amends SFAS 123, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002. SFAS 148 has not had any effect on the Company’s financial position or results of operations. See additional required disclosures at “Note 10. Employee Benefit Plans.”
3.
Acquisitions
2001 Acquisitions
During 2001, we made small miscellaneous acquisitions of undeveloped acreage. No material proved property acquisitions were made.
2002 Acquisitions
On January 4, 2002 we closed the purchase of our Central Permian properties. These properties were purchased from Conoco for approximately $50.1 million. The properties include two major operated fields: East Cowden Grayburg and Fuhrman-Nix; and two non-operated fields: North Cowden and Yates. During the second quarter of 2002, we closed a second follow-on acquisition of additional working interests in the East Cowden Field for $8.3 million.
On August 29, 2002, we completed an acquisition of interests in oil and natural gas properties in southeast Utah’s Paradox Basin. The final purchase price after the exercise of preferential rights was $17.9 million ($16.7 million after closing adjustments). The properties are divided between two oil producing units: the Ratherford Unit operated by ExxonMobil and the Aneth Unit operated by Chevron Texaco.
2003 Acquisitions
On July 31, 2003, we closed the initial acquisition of the North Louisiana properties. Subsequently, we have purchased several smaller interests in these properties. The original purchase was effective June 1, 2003. The Company purchased interests in natural gas properties in North Louisiana (the “Elm Grove” acquisition) from a group of private sellers at a cost of $54.6 million. Beginning August 1, 2003, revenues and expenses from these properties have been included in the Company’s Consolidated Statements of Operations and drilling costs have been included in “Development of oil and natural gas properties’ in the Consolidated Statements of Cash Flows. From June 1, 2003 to July 31, 2003, revenues, expenses, and development capital of the properties were treated as adjustments to the purchase price. The properties are
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 2% to 38% across 1,800 net acres in 15 sections.
These acquisitions have been accounted for as purchases. The operating results of the acquired properties have been included in our consolidated financial statements since the date of acquisition.
4.
Commitments and Contingencies
Leases
We lease office space and equipment that have remaining non-cancelable lease terms in excess of one year. The following table summarizes by year our remaining non-cancelable future payments under operating leases as of December 31, 2003 (in thousands):
Our operating lease rental expense was approximately $1.5 million, $0.9 million, and $0.7 million in 2003, 2002, and 2001, respectively.
Asset Retirement Obligations
The Company’s primary asset retirement obligations relate to future plugging and abandonment expenses on our oil and natural gas properties and related facilities disposal. As of December 31, 2003, the Company had $2.7 million held in an escrow account from which funds are released only for reimbursement of plugging and abandonment expenses on our Bell Creek property. This amount is included in ‘Other assets’ in the accompanying Consolidated Balance Sheet. The following table summarizes the changes in the Company’s future abandonment liability recorded in ‘Future abandonment cost’ on the Company’s Consolidated Balance Sheet from the liability initially recorded upon adoption of SFAS 143 on January 1, 2003 through December 31, 2003 (in thousands):
The pro-forma asset retirement obligation as of December 31, 2001 and 2000 would have been $4.1 million and $4.2 million, respectively, had the Company adopted SFAS 143 prior to January 1, 2001.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5.
Accounts Payable and Accrued Liabilities
Other current liabilities were as follows at December 31 (in thousands):
6.
Indebtedness
The following table details the Company’s indebtedness at December 31 (in thousands):
Prior to restructuring our debt on June 25, 2002 (see below), the Company’s operating subsidiary maintained a credit agreement with a group of banks that matured in May 2004. The Company guaranteed the subsidiary’s obligations under the credit agreement and pledged the stock and other equity interests of its subsidiaries to secure the guaranty.
On June 25, 2002, the Company sold $150 million of 8 3/8% Senior Subordinated Notes maturing on June 15, 2012 (the “Notes”). The offering was made through a private placement pursuant to Rule 144A. Subsequently, the Company filed a registration statement on Form S-4/ A, which was declared effective on December 6, 2002. The Company received net proceeds of $145.6 million from the sale of the Notes, after deducting debt issuance costs. The proceeds were used to repay and retire the Company’s prior credit facility ($143.0 million), to pay the fees and expenses related to a new revolving credit facility ($1.5 million), and to hold in reserve for the Paradox Basin acquisition ($1.1 million).
All of the Company’s subsidiaries are currently subsidiary guarantors of the Notes. Since (i) each subsidiary guarantor is 100% owned by the Company, (ii) the Company has no assets or operations that are independent of its subsidiaries, (iii) the subsidiary guarantees are full and unconditional and joint and several and (iv) all of the Company’s subsidiaries are subsidiary guarantors, the Company has not included the financial statements of each subsidiary in this report. The subsidiary guarantors may without restriction transfer funds to the Company in the form of cash dividends, loans and advances.
Concurrently with the issuance of the Notes, the Company also entered into a new revolving credit facility (the “Facility”) on June 25, 2002. Borrowings under the Facility are secured by a first priority lien on the Company’s proved oil and natural gas reserves. Availability under the Facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The amount available under the Facility at December 31, 2003 was $270.0 million, with $29.0 million outstanding as of December 31, 2003. The maturity date of the Facility is June 25, 2006.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Amounts outstanding under the Facility are subject to varying rates of interest based on the amount outstanding and the Company’s borrowing base. Based on our current $270.0 million borrowing base, our applicable interest rates are calculated as follows:
During 2003 and 2002, the weighted average interest rate under the Facility was 9.6% and 8.2%, respectively.
Additionally, under the Facility, the Company is subject to certain affirmative, negative, and financial covenants. These include limitations on incurrence of additional debt, restrictions on asset dispositions and restricted payments, maintenance of a 1.0 to 1.0 current ratio, and maintenance of an EBITDA, as defined, to interest expense ratio of at least 2.5 to 1.0. As of December 31, 2003, the Company was in compliance with all covenants.
The following table illustrates the Company’s long-term debt maturities at December 31, 2003 (in thousands):
Consolidated cash payments for interest were $16.2 million, $13.2 million, and $6.4 million, respectively, for 2003, 2002, and 2001.
7.
Taxes
Income Taxes
The components of the Company’s total income tax expense including amounts related to items shown net of income taxes on the statements of operations were attributed to the following items (in thousands):
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The components of the income tax provision related to income/ loss before cumulative effect of accounting change and extraordinary loss are as follows (in thousands):
Reconciliation of income tax expense with tax at the Federal statutory rate is as follows (in thousands):
The major components of the net current deferred tax asset and net long-term deferred tax liability are as follows at December 31 (in thousands):
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cash income tax payments in the amount of $1.5 million were made in 2003 and in 2001. No cash income tax payments were made in 2002.
Taxes Other than Income Taxes
Taxes other than income taxes were comprised of the following (in thousands):
8.
Stockholders’ Equity
Public Offerings of Common Stock
On March 8, 2001, the Company priced its shares to be issued in its initial public offering (“IPO”) and began trading on the New York Stock Exchange the following day under the ticker symbol “EAC”. Immediately prior to Encore’s IPO, all of the outstanding shares of Class A and Class B stock held by management and institutional investors were converted into 2,630,203 and 20,249,758 shares, respectively, of a single class of common stock. Through the IPO, the Company sold an additional 7,150,000 shares of common stock to the public at the offering price of $14.00 per share, resulting in total outstanding shares of 30,029,961. The Company received $91.5 million in net proceeds after deducting the underwriter’s discounts and commissions and related offering expenses. The proceeds received from the IPO were used to pay down debt outstanding under our credit facility.
On November 13, 2003, the Company priced a public offering of 8.0 million shares of Encore’s common stock at a price to the public of $20.25 per share. The underwriters also exercised their over-allotment option for an additional 1.06 million shares of common stock, at a price of $20.25 per share, on December 2, 2003, for a total of 9.06 million shares. The Company used all of the net proceeds to repurchase 6,866,643 shares of Encore’s common stock from J.P. Morgan Partners (SBIC), LLC (“J.P. Morgan”) and 2,193,357 shares from Warburg Pincus Equity Partners L.P. (“Warburg Pincus”) at a price of $19.3775 per share. The 9.06 million shares the Company purchased were retired upon
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
repurchase. Encore’s total shares outstanding did not change as a result of this offering. Net proceeds from the original offering and the over-allotment option totaled approximately $175.6 million, after deducting underwriting discounts and commissions and the estimated expenses of the offering. After giving effect to the repurchase, J.P. Morgan no longer beneficially owns any of Encore’s common stock and Warburg Pincus beneficially owns 24.5% of Encore’s common stock.
Common Stock Option Exercises
During the years ended December 31, 2003 and 2002, employees of the Company exercised 145,727 and 3,666 options, respectively. The Company received proceeds from the option exercises of $2.0 million and $0.1 million in the years ended December 31, 2003 and 2002, respectively, related to these option exercises.
Preferred Stock
The Company has authorized a class of undesignated preferred stock consisting of 5,000,000 shares, none of which are issued and outstanding. The Board of Directors has not determined the rights and privileges of holders of such preferred stock and we have no current plans to issue any shares of preferred stock.
Non-Cash Stock Based Compensation Expense on Class A Stock
The Company followed variable plan accounting for the Class A stock sold to management. Accordingly, compensation expense was based on the excess of the estimated fair value of the Class A stock over the amount paid by the shareholders. Compensation expense was adjusted in each reporting period based on the most recent fair value estimates until the measurement date occurred. Compensation expense was recorded over the expected service period of the Class A stock, which was based on a vesting schedule. The Class A stock vested 25% upon issuance and an additional 15% per year for the following five years. Prior to September 1, 2000, the Company estimated the fair value of our Class A common stock based on discounted cash flow estimates of our oil and natural gas properties. Beginning on September 1, 2000, we estimated the fair value of the Class A stock based on 90% of the estimated offering price in the Company’s IPO. The measurement date occurred on March 8, 2001, the date of the IPO, as after this date the Class A shareholders were no longer required to make future capital contributions. Total compensation expense on the Class A shares using the IPO price of $14.00 per share was $35.6 million. Based on the estimated fair values and vesting at the end of each period, the Company recorded $9.6 million of compensation expense for 2001 and $26.0 million in 2000. The $9.6 million recorded in 2001 represented the final compensation expense to be recorded related to the Class A shares.
9.
Earnings Per Share (“EPS”)
Under Statement of Financial Accounting Standards No. 128, the Company must report basic EPS, which excludes the effect of potentially dilutive securities, and diluted EPS, which includes the effect of all potentially dilutive securities. EPS for the periods presented is based on weighted average common shares outstanding for the period.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table reflects EPS data for the years ended December 31 (in thousands, except per share data):
(a)
There were no antidilutive options or antidilutive restricted stock outstanding for the year ended December 31, 2003 and December 31, 2001. Options to purchase 272,177 shares of common stock were outstanding but not included in the above calculation of 2002 diluted earnings per share because their effect would be antidilutive. Additionally, the Company issued 129,328 shares of restricted stock at the end of 2002 which are not included in the calculation of 2002 diluted earnings per share because their effect on the shares outstanding would be nominal.
10.
Employee Benefit Plans
401(k) plan
We make contributions to the Encore Acquisition Company 401(k) Plan, which is a voluntary and contributory plan for eligible employees. Our contributions, which are based on a percentage of matching employee contributions, totaled $0.5 million in 2003, $0.5 million in 2002, and $0.4 million in 2001. The Company’s 401(k) plan does not currently allow employees to invest in securities of the Company.
Incentive Stock Plans
During 2000, the Company’s Board of Directors approved the 2000 Incentive Stock Plan (the “Plan”). The purpose of the Plan is to attract, motivate, and retain selected employees of the Company and to provide the Company with the ability to provide incentives more directly linked to the profitability of the business and increases in shareholder value. All directors and full-time regular employees of the Company and its subsidiaries and affiliates are eligible to be granted awards under the Plan. The total number of shares of common stock reserved and available for distribution pursuant to the Plan is 1.8 million. The Plan provides for the granting of incentive stock options, non-qualified stock options, and restricted stock at the discretion of the Company’s Board of Directors.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
All options granted under the Plan have a strike price equal to the market price on the date of grant. Additionally, all have a ten-year life and vest equally over a two or three-year period. The following table summarizes the changes in the number of outstanding options and their related weighted average strike prices during 2003, 2002, and 2001:
(a)
During 2003 and 2002, 15,000 and none of the options granted, respectively, were granted to non-employee directors. The weighted average fair value of individual options granted in 2003 and 2002 was $6.38 and $6.91, respectively.
Additional information about common stock options outstanding and exercisable at December 31, 2003 is as follows:
Under the Plan during 2003 and 2002, the Company issued 45,461 and 129,328 shares, respectively, of restricted common stock to employees. Of these, 45,461 shares issued in 2003 and 77,901 shares issued in 2002 vest in equal installments over a five year period evenly in years three, four, and five and depend only on continued employment for future issuance. These represent a fixed award per APB 25 and compensation expense is being recorded over the related five-year service period. Of the remaining 51,427 shares issued in 2002, only 34,464 remain outstanding at December 31, 2003. These were issued to two members of senior management and also vest in equal installments over a five year period evenly in years three, four, and five. However, these shares not only depend on the passage of time and continued employment, but on certain performance measures for their future issuance. These represent a variable award under APB 25, and thus, the full amount of compensation expense to be recorded for these shares will not be known until their eventual issuance as it is dependent on the price of the Company’s common stock on that date. The closing stock price on the date of grant in 2002 was $18.60 and was $24.65 on December 31, 2003.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS 123 disclosures
Under SFAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option-pricing model. See “Stock-based Compensation” in Note 2. The following amounts represent weighted average values used in the model to calculate the fair value of the options granted during 2003, 2002, and 2001:
11.
Financial Instruments
The following table sets forth the book value and estimated fair value of the Company’s financial instruments (in thousands):
The book value of cash and cash equivalents approximates fair value because of the short maturity of these instruments. The fair value of our 8 3/8% bonds was determined using their open market quote as of December 31, 2003. The difference between book value and fair value represents the premium on that date. The book value of the Facility approximates the fair value as the interest rate is variable. The plugging bond is classified as held to maturity and therefore is recorded at amortized cost, which at December 31, 2003 is less than fair value. Commodity contracts and interest rate swaps are marked to market each quarter in accordance with the provisions of SFAS 133.
Commodity Derivatives
The Company hedges commodity price risk with swap contracts, put contracts, and collar contracts and hedges interest rate risk with swap contracts. Swap contracts provide a fixed price for a notional amount of volume. Put contracts provide a fixed floor price on a notional amount of volume while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide floor price for a notional amount of volume while allowing some additional price participation if the relevant index price closes above the floor price. Additionally, we occasionally sell put contracts with a strike price well below the floor price of the collar. These short put contracts do not qualify for hedge accounting under SFAS 133, and accordingly, the mark-to-market change in the value of these contracts is recorded as fair value gain/loss in the statement of operations.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company has several oil and natural gas put contracts in place at December 31, 2003 which the Company did not designate as cash flow hedges, and thus they are also marked to market through earnings each quarter. Some instances management has determined it is more cost effective to not designate certain derivatives as hedges. At December 31, 2003, we had oil put contracts of 1,500 Bbls per day in the first half of 2004, 2,500 Bbls of oil put contracts in the second half of 2004, and natural gas put contracts of 5,000 Mcf per day for 2004 that were not designated as cash flow hedges. The fair value of these contracts at December 31, 2003 was $0.9 million.
In order to more effectively hedge the cash flows received on our oil and natural gas production, the Company enters into financial instruments whereby we swap certain per Bbl or per Mcf floating market indices for a fixed amount. These market indices are a component of the price the Company is paid on its actual production and by fixing this component of our marketing price, we are able to realize a net price with a more consistent differential to NYMEX. Since NYMEX is the basis of all our derivative oil hedging contracts and some of our natural gas contracts, a more consistent differential results in more effective hedges. However, management has elected not to use hedge accounting for certain of these contracts. Instead, we mark these contracts to market each quarter through “Derivative fair value (gain) loss’ in the Consolidated Statements of Operations. Thus, as these contracts do not change the Company’s overall hedged volumes, average prices presented in the table below are exclusive of any effect of these non-hedge instruments. As of December 31, 2003, the mark-to-market value of these contracts is $0.1 million.
The following tables summarize our open commodity derivative positions designated as cash flow hedges as of December 31, 2003:
Oil Hedges at December 31,
Natural Gas Hedges at December 31,
As a result of all of our hedging transactions for oil and natural gas we recognized a pre-tax reduction in revenues of approximately $15.3 million, $5.2 million, and $12.8 million in 2003, 2002, and 2001, respectively. Based on the fair value of our hedges at December 31, 2003, our unrealized pre-tax loss recorded in other comprehensive income related to outstanding hedges is $13.9 million for oil and $2.1 million for natural gas. Of the total deferred hedge loss at December 31, 2003 related to commodity contracts, $12.1 million relates to 2004 contracts, and $1.7 million, $1.2 million, $1.0 million relate to 2005, 2006, and 2007 contracts, respectively.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Interest Rate Derivatives
As discussed in “Note 6. Indebtedness,” in conjunction with the sale of the Notes, the Company repaid all amounts outstanding under its previous credit facility on June 25, 2002, and terminated the prior revolving credit facility on that date. At the time, the Company had three interest rate swaps outstanding, with a notional amount of $30 million each, which swapped LIBOR based floating rates for fixed rates. According to the provisions of SFAS 133, these no longer qualified for hedge accounting. Their unrealized loss of $3.8 million through June 25, 2002 was recognized in accumulated other comprehensive income, and is being amortized to interest expense over the original life of the swaps as follows (in thousands):
During the third quarter of 2002, the Company cash settled one of three interest rate swaps discussed above and during the first quarter of 2003, the Company cash settled the remaining two. This resulted in a gain of $0.6 million in 2003 and a loss of $0.4 million in 2002, which was included in “Derivative fair value (gain) loss’ in the Statements of Operations.
The following table summarizes the Company’s only remaining interest rate swap contract at December 31, 2003:
As a result of our hedging transactions for interest, we recognized in interest expense a pre-tax loss of approximately $1.9 million, $1.6 million, and $0.7 million in 2003, 2002, and 2001, respectively. Additionally, $1.5 million gain was recognized in “Derivative fair value (gain) loss’ in 2003 for settlements and changes in fair value of our current interest rate swap, which does not qualify for hedge accounting.
The actual gains or losses we realize from our derivative transactions may vary significantly from the deferred loss amount recorded in equity at December 31, 2003 due to fluctuation of prices in the commodities markets and/or fluctuations in the floating LIBOR interest rate.
Counterparty Risk
The Company’s counterparties to hedging contracts include: Paribas BNP; Deutsche Bank; Koch; Morgan Stanley; Mitsui & Co; Shell Trading; Credit Lyonnais; J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. Approximately 35%, 23%, 20%, and 16% of estimated oil production hedged is committed to Morgan Stanley, J. Aron & Company, Deutsche Bank, and Credit Lyonnais, respectively. Approximately 42%, 33%, and 25% of our hedged gas production is contracted with BNP Paribas, J. Aron & Company, and Morgan Stanley, respectively. Performance on all of J. Aron & Company’s contracts with the Company is guaranteed by their parent Goldman, Sachs & Co. We feel the credit-worthiness of our current counterparties is sound and we do not anticipate any non-performance of
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
contractual obligations. However, as long as each counterparty maintains an investment grade credit rating, pursuant to our hedging contracts, no collateral is required.
In order to mitigate the credit risk of financial instruments, the Company enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between the Company and a given counterparty. Instead of treating each financial transaction between the Company and its counterparty separately, the master netting agreement enables the Company and its counterparty to aggregate all financial trades and treat them as a single agreement. This arrangement benefits the Company in three ways. First, the netting of the value of all trades reduces the requirements of daily collateral posting by the Company. Second, default by a counterparty under one financial trade can trigger rights for the Company to terminate all financial trades with such counterparty. Third, netting of settlement amounts reduces the Company’s credit exposure to a given counterparty in the event of close-out.
12.
Termination of Enron Hedges
On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. Prior to this date, the Company had entered into oil and natural gas hedging contracts with Enron, many of which were set to expire at December 31, 2001; however, others related to 2002 and 2003. As a result of the Chapter 11 bankruptcy declaration and pursuant to the terms of the Company’s contract with Enron, we terminated all outstanding oil and natural gas derivative contracts with Enron as of December 12, 2001. According to the terms of the contract, Enron is liable to the Company for the mark-to-market value of all contracts outstanding on that date, which totaled $6.6 million. Additionally, Enron failed to make timely payment of $0.4 million in 2001 hedge settlements. Both of these amounts remained outstanding as of December 31, 2001. Due to the uncertainty of future collection of any or all of the amounts owed to the Company by Enron, the Company recorded an allowance for the full amount of the receivable of $7.0 million.
At the time of termination, the market price of our commodity contracts with Enron exceeded their amortized cost on our balance sheet, giving rise to a gain. In accordance with the provisions of SFAS 133, this gain was recorded in other comprehensive income and was reversed into earnings during 2003 and 2002. The following table illustrates the amortization of this amount to revenue by year (in thousands):
During the first quarter of 2003, due to continued uncertainty of any ultimate collection and continuing legal fees, the Company sold its entire Enron receivable to a third party for $0.5 million. As the receivable was fully reserved, this amount was recorded as a gain in 2003 and included in ‘Other operating expense’ in the Consolidated Statements of Operations. The Company no longer has any claims outstanding against Enron and accordingly has eliminated the previously recorded $7.0 million receivable and related allowance from the accompanying consolidated balance sheet as of December 31, 2003.
The Company actively evaluates the credit exposure related to its derivatives and receivables, and considers its history with the debtor, how long the amount has been outstanding, potential offsets to the amount owed, and general economic conditions. Other than the Enron loss, the Company has not become aware of any conditions which warrant an allowance or write-off of a receivable or derivative position.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
13.
Impairment of Long-Lived Assets
Throughout 2001, futures prices for oil and natural gas continued to decline from their December 31, 2000 levels. The SEC price case used for our 2000 reserve estimate was $26.80 per Bbl and $9.77 per Mcf dropping to $19.84 per Bbl and $2.57 per Mcf for the 2001 estimate. Although the SEC price case does not necessarily coincide with management’s estimates of future prices, this indicated the need to assess our oil and natural gas properties for any possible impairment. Thus, we compared the undiscounted future cash flows for each of our oil and natural gas properties to their net book value, which indicated the need for an impairment charge on certain properties. We then compared the net book value of the impaired assets to their estimated fair value, which resulted in a write-down of the value of proved oil and natural gas properties of $2.6 million. Fair value was determined using estimates of future production volumes and estimates of future prices we might receive for these volumes discounted back to a present value using a rate commensurate with the risks inherent in the industry. We performed a similar review at December 31, 2003 and 2002, and determined no impairment charge was necessary.
14.
Subsequent Events (unaudited)
On March 2, 2004, the Company entered into a stock purchase agreement to acquire all of the outstanding common stock of Cortez Oil & Gas, Inc., a privately held, independent oil and gas company (“Cortez”), for total consideration of approximately $123.0 million. The Company intends to fund the acquisition initially with bank debt under the Company’s existing credit facility. The acquired oil and natural gas assets from Cortez are in the same areas as our producing properties located in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico, and in our Mid Continent area, including the Anadarko and Arkoma Basins of Oklahoma, and the Barnett Shale north of Fort Worth, Texas. We expect to close the transaction in the second quarter of 2004, however, the closing is subject in some respects to the Company’s due diligence review and other closing conditions, and there can be no assurance that the closing will occur as expected.
In connection with the Cortez acquisition, we entered into several oil and natural gas hedges subsequent to December 31, 2003. The table below shows the terms of these contracts as of March 4, 2004:
Additional Oil Derivative Contracts at March 4, 2004
Additional Natural Gas Derivative Contracts at March 4, 2004
SUPPLEMENTAL INFORMATION
Capitalized Costs Relating to Oil and Gas Producing Activities
The capitalized cost of oil and natural gas properties at December 31, 2003 and 2002 are as follows (in thousands):
Costs Incurred Relating to Oil and Gas Producing Activities
The following table summarizes costs incurred related to oil and natural gas properties:
(1)
The Company adopted SFAS 143 on January 1, 2003 which requires us to capitalize additional asset cost equal to the amount of our discounted asset retirement obligation assumed in a property purchase or incurred in the drilling of new wells. Had the Company adopted SFAS 143 prior to January 1, 2001, the Company’s acquisition cost incurred on a pro-forma basis would have been increased by $0.7 million and zero for the years ended December 31, 2002 and 2001, respectively. The effect on the Company’s development cost incurred on a pro-forma basis would have been insignificant.
Oil & Natural Gas Producing Activities (unaudited)
The estimates of the Company’s proved oil and natural gas reserves, which are located entirely within the United States, were prepared in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. Proved oil and natural gas reserve quantities are based on estimates prepared by Miller and Lents, Ltd., who are independent petroleum engineers.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods assumed or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. In accordance with the Securities and Exchange Commission’s guidelines, the Company’s estimates of future net cash flows from the properties and the representative value thereof are made using oil and natural gas prices in effect as of the dates of such estimates and are held constant throughout the life of the properties. Average prices used in estimating net cash flows at December 31, 2003, 2002, and 2001 were $32.55, $31.20, and $19.84 per barrel, respectively, for oil and $5.83, $4.79, and $2.57 per Mcf, respectively, for natural gas. The net profits interest on our Cedar Creek Anticline properties has been
deducted from future cash inflows in the calculation of Standardized Measure. The Company’s reserve and production quantities have been reduced by the amounts attributable to the net profits interest. In addition, net future cash inflows have not been adjusted for hedge positions outstanding at the end of the year. The future cash flows are reduced by estimated production costs and development costs, which are based on year-end economic conditions and held constant throughout the life of the properties, and by the estimated effect of future income taxes. Future income taxes are based on statutory income tax rates in effect at year end, the Company’s tax basis in its proved oil and natural gas properties, and the effect of net operating loss, alternative minimum tax and Section 43 credits, and other carry forwards.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. Oil and natural gas reserve engineering is and must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and estimates of other engineers might differ materially from those included in this Annual Report on Form 10-K. The accuracy of any reserve estimate is a function of the quality of available data and engineering, and estimates may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered. Reserve estimates are integral to management’s analysis of impairments of oil and natural gas properties and the calculation of depletion, depreciation, and amortization on these properties.
Estimated net quantities of proved oil and natural gas reserves of the Company were as follows:
The change in proved reserves were as follows for the years ended:
The Standardized Measure of discounted estimated future net cash flows and changes therein related to proved oil and natural gas reserves (in thousands) is as follows at:
Primary changes in the Standardized Measure of discounted estimated future net cash flows (in thousands) are as follows for the year ended:
Selected Quarterly Financial Data
The following table sets forth selected quarterly financial data for the years ended December 31, 2003 and 2002:
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On April 1, 2002, we dismissed Arthur Andersen LLP as our independent accountants effective as of that date. The decision to dismiss Arthur Andersen LLP was recommended by the Audit Committee of the Board of Directors and was approved by the Board of Directors on April 1, 2002.
Arthur Andersen’s report on the Company’s consolidated financial statements for the fiscal year ended December 31, 2001 did not contain an adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty or audit scope. Arthur Andersen LLP included in its opinion explanatory language related to the Company’s change in its method of accounting for derivatives as a result of the Company’s adoption of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” During 2001 and the period from January 1, 2002 through the date of Arthur Andersen LLP’s termination, there were no disagreements between us and Arthur Andersen LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, that, if not resolved to the satisfaction of Arthur Andersen LLP, pursuant to Item 304(a)(1) of Regulation S-K, would have caused it to make reference to the subject matter of the disagreements in its report.
As required under the regulations of the SEC, we provided Arthur Andersen LLP with a copy of our disclosure in connection with this matter and requested Arthur Andersen LLP to furnish us with a letter addressed to the SEC stating whether it agreed with our statements and, if not, stating the respects in which it did not agree. Arthur Andersen LLP’s letter was filed as Exhibit 16.1 to our Current Report on Form 8-K filed with the SEC on April 5, 2002.
Effective April 11, 2002, we engaged Ernst & Young LLP, as our new independent accountants for the fiscal year ending December 31, 2002. The decision to appoint Ernst & Young LLP was recommended by the Audit Committee of the Board of Directors and was approved by the Board of Directors on April 1, 2002.
There have been no disagreements with our independent accountants on our accounting or financial reporting that would require our independent accountants to qualify or disclaim their report on our consolidated financial statements, or otherwise require disclosure in this Form 10-K.
Item 9A.
Item 9A.
Controls and Procedures
Our Chief Executive Officer and our Chief Financial Officer (our principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of the end of the period covered by this annual report on Form 10-K, that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.
We have adopted a Code of Business Conduct and Ethics covering our directors, officers, and employees, which is available free of charge on our Internet website (www.encoreacq.com).
Item 11.
Item 11.
Executive Compensation
The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.
Item 14.
Item 14.
Principal Accountant Fees and Services
The information required in response to this item is set forth in the Company’s definitive proxy statement for the annual meeting of stockholders to be held on April 29, 2004 and is incorporated herein by reference.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as a part of this Report at page 48:
1. Financial Statements:
2. Financial Statement Schedules:
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the consolidated financial statements.
(b) Reports on Form 8-K
We filed the following reports on Form 8-K during the quarter ended December 31, 2003:
1.
On November 4, 2003, we filed a Form 8-K to furnish certain earnings-related information under Items 7 and 12.
2.
On November 7, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the appointment of Roy W. Jageman as our Chief Financial Officer.
3.
On November 10, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding a public offering of up to 9.2 million shares of our common stock and the use of proceeds therefrom.
4.
On November 14, 2003, we filed an Item 5 and Item 7 Form 8-K to disclose the execution of an underwriting agreement with respect to the public offering of up to 9.2 million shares of our common stock and the execution of a stock purchase agreement with respect to the repurchase of up to 9.2 million shares of our common stock from J.P. Morgan Partners (SBIC), LLC and Warburg, Pincus Equity Partners L.P.
5.
On November 20, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the closing of a public offering of 8.0 million shares of our common stock and the use of proceeds therefrom.
6.
On December 3, 2003, we filed a Form 8-K to furnish information under Items 7 and 9 regarding the sale of 1,060,000 shares of our common stock pursuant the exercise of the underwriters’ over-allotment option and the use of proceeds therefrom.
(c) Exhibits
See Exhibits to Index on the following page for a description of the exhibits filed as a part of this report.
INDEX TO EXHIBITS
*
Filed herewith
+
Management contract or compensatory plan, contract or arrangement.
Copies of the above exhibits not contained herein are available at the cost of reproduction to any security holder upon written request to the Assistant Treasurer, Encore Acquisition Company, 777 Main Street, Suite 1400, Fort Worth, Texas 76102.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March, 2004.
ENCORE ACQUISITION COMPANY
By:
/s/ I. JON BRUMLEY
I. Jon Brumley
Chief Executive Officer
KNOW ALL MEN BY THESE PRESENTS, that each individual whose signature appears below constitutes and appoints I. Jon Brumley and Roy W. Jageman, and each of them, his true and lawful attorneys-in-fact and agents with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this report, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on March 11, 2004.