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, 2004.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock, $0.01 par value, is listed on the NYSE under the symbol “EAC.” The following table sets forth quarterly high and low sales prices of our common stock for each quarterly period of 2004 and 2003:
On February 28, 2005, we had approximately 220 shareholders of record.
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 and the indentures governing our 83/8% and 61/4% notes. Future debt agreements may also restrict our ability to pay dividends.
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 our consolidated financial position and results of operations should be read in conjunction with our financial statements and notes and the supplemental oil and natural gas disclosures included elsewhere in this Report. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions, and resources. The words “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should” and similar expressions identify forward-looking statements. Actual results could differ materially from those stated in the forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the headings: “Special Note Regarding Forward-Looking Statements” beginning on page 41 and “Factors That May Affect Future Results and Financial Condition” beginning on page 42.
Overview
We engage in the acquisition, development, exploitation, exploration, and production of onshore North American oil and natural gas reserves. Our business strategies include maintaining an active low-risk development drilling program, maximizing existing reserves and production through high-pressure air injection projects, expanding our reserves, production and drilling inventory through a disciplined acquisition program, exploring for reserves and operating in a cost effective, efficient, and safe manner.
Our financial results and ability to generate cash depend upon many factors, particularly the price of oil and natural gas. Commodity prices strengthened considerably in 2004. The average oil price for the NYMEX futures market was $41.26 per barrel for 2004 as compared to $31.04 per barrel for 2003. The average natural gas price for the NYMEX futures market was $6.11 per MMBTU for 2004 as compared to $5.50 per MMBTU for 2003. Commodity prices are influenced by many factors that are outside of our control. We cannot predict future commodity prices. For this reason, we attempt to mitigate the effect of commodity price risk by hedging a portion of our future production.
In 2004, we saw the industry and commodity markets begin to reflect a higher long-term outlook for commodity prices. As a result during the year, the industry continued to bid up the price of reserves to historically high levels. However, we were fortunate to be able to expand our core areas with the purchase of Cortez Oil & Gas, Inc. and natural gas properties in the Overton Field. As the year progressed and the cost of acquisitions continued to rise, we began to identify exploration projects within our core areas that complemented our current asset portfolio. We believe the rate of return on our exploration projects will meet or exceed the rate of return available in the current acquisition market. We will, however, continue to evaluate acquisition opportunities as they arise and to the extent we believe we can expect to realize a good rate of return to our shareholders.
We continue to believe that a portfolio of long-lived quality assets will position the Company for future success, and that reserve replacement is a key statistical measure of our success in growing our asset base. During 2004, we replaced 456% of our 2004 production. Our development program replaced 210% of production and acquisitions replaced 246% of production. See “Business and Properties - General - Oil and Natural Gas Production and Reserves” on page 3 for the calculation of our reserve replacement ratios.
Also in 2004, we continued to see positive results from our Phase I high-pressure air injection project at the Pennel unit. Pennel is the largest unit of the CCA units. The Phase II implementation is anticipated to be complete by the end of 2005 and initial air injection is scheduled to begin in the second quarter of 2005. In the Little Beaver unit at the southern end of the CCA, we have completed the implementation of Phase I and II HPAI projects. Our independent reserve engineers, Miller and Lents, Ltd. estimated that we added 9.1 million and 12.5 million barrels, respectively, of proved undeveloped oil reserves associated with our high pressure air injection program at the end of 2004 and 2003. For the long term, we believe that high-pressure air injection technology can be applied throughout the Cedar Creek Anticline.
2004 Highlights
Our financial and operating results for the year ended December 31, 2004 include the following:
•
Oil and natural gas reserves increased 23% to 173 MMBOE. During 2004, we added 41.2 MMBOE, replacing 456% of the 9.0 MMBOE produced in 2004. See “Business and Properties - General - Oil and Natural Gas Production and Reserves” on page 3 for the calculation of our reserve replacement ratio. Oil reserves accounted for 77% of total proved reserves, and 71% of proved reserves are developed. The estimated pretax present value of our reserves increased by 59% to over $1.6 billion (using a 10% discount rate and constant year end prices of $43.46 for oil and $6.19 for natural gas). The Standardized Measure at December 31, 2004 is $1.2 billion. Standardized Measure differs from PV-10 by $458.9 million, because Standardized Measure includes the effect of asset retirement obligations and future income taxes.
•
Production volumes for 2004 increased 11% to 9.0 MMBOE (24,665 BOE per day) compared with 2003 production of 8.1 MMBOE (22,218 BOE per day). Oil represented 74% and 81% of our total production in 2004 and 2003, respectively. The increase in production is due to our continued successful development and exploitation program as well as acquisitions.
•
Net income for 2004 increased to $82.1 million, or $2.58 per diluted share, on revenues of $298.5 million. This compares to 2003 net income of $63.6 million, or $2.10 per diluted share, on revenues of $220.1 million. For 2004, cash flow from operations increased 39% to $171.8 million
from $123.8 million in cash flow from operations in 2003. The increase in net income and cash flow from operations in 2004 was primarily a result of higher production and higher commodity prices throughout the year.
•
We invested $187.6 million in development, exploitation, and exploration projects during 2004, including $39.6 million in our high-pressure air injection projects in the Little Beaver unit and the Pennel unit of the CCA. In 2004, we drilled 168 gross operated productive wells and 67 gross non-operated productive wells, for a total of 235 gross productive wells for the year. On a net basis, we drilled 156.4 operated productive wells and participated in 8.8 non-operated productive wells in 2004. Out of the 168 (156.4 net) operated productive wells, 12 (11.5 net) wells were service wells. We also drilled 5 (4.5 net) non-productive wells in 2004, of which 4 (3.9 net) were exploratory wells.
•
We acquired natural gas producing properties and undeveloped leases in the Overton Field located in Smith County, Texas, additional interests in Elm Grove Field, and all of the capital stock of Cortez Oil & Gas, Inc.
•
On April 2, 2004, we issued and sold $150.0 million of 61/4% Senior Subordinated Notes due April 15, 2014. We received approximately $146.4 million after paying all costs associated with the offering. The net proceeds were used to fund the acquisition of Cortez and repay amounts outstanding under our revolving credit facility.
•
On June 10, 2004, we issued and sold 2,000,000 shares of our common stock to the public at a price of $26.95 per share. The net proceeds of the offering, after underwriting discounts and commissions and other expenses, were $52.9 million. We used the net proceeds of this offering to repay indebtedness under our revolving credit facility and for general corporate purposes.
•
On June 30, 2004, we filed a new universal shelf registration statement on Form S-3 with the SEC. The registration statement, which was declared effective by the SEC on July 9, 2004, allows us to issue an aggregate of $500 million of common stock, preferred stock, senior debt and subordinated debt.
•
On August 19, 2004, we improved our financial flexibility and liquidity by amending and restating our credit facility and increasing our borrowing base from $270 million to $400 million. At December 31, 2004, we had $79 million outstanding under the revolving credit facility, $30 million in outstanding letters of credit, and $291 million available.
Results of Operations
Comparison of 2004 to
Set forth below is our comparison of our results of operations for the year ended December 31, 2004 with our results of operations for the year ended December 31, 2003.
Revenues and Production. The following table illustrates the primary components of oil and natural gas revenue for the years ended December 31, 2004 and 2003, as well as each year’s respective oil and natural gas volumes (dollars in thousands except per unit amounts):
Oil revenues increased $44.3 million to $220.6 million in 2004 over 2003 as production increased 78 MBbls and our average realized price increased $6.32 per Bbl. Oil revenues were reduced by $34.7 million in 2004 due to our hedging program. The $5.20 per Bbl reduction to our wellhead oil price due to hedging represented a $3.10 per Bbl greater reduction than in 2003. The increase in oil production resulted from success through our 2004 drilling program, uplift from our HPAI program, and acquisitions. In addition, our oil wellhead revenue was reduced by $12.3 million and $5.6 million in 2004 and 2003, respectively, for the net profits interests payments related to our CCA properties.
Natural gas revenues increased in 2004 by $34.1 million to $77.9 million due to increased production of 5,038 MMcf and an increase in the net wellhead price received. The increase in net wellhead price received of $0.76 per Mcf resulted as the average NYMEX price increased $0.61 per Mcf over the same period. The increase in natural gas production resulted from success through our 2004 drilling program and acquisitions.
For the full year 2005, production is expected to increase 8% to 12% from 2004 levels primarily due to our 2005 capital budget of $223.0 million and the full year effect of our 2004 acquisitions.
The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. For comparability and accountability, we take a constant approach to budgeting commodity prices. We presently analyze our inventory of capital projects on $30.00 per Bbl and $5.00 per Mcf NYMEX prices. We do not assume any escalation of commodity prices when preparing our capital budget. 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 $1.8 million for oil and $0.3 million for natural gas during 2005. 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 in 2005 of $6.2 million for
oil and $0.1 million for natural gas. These payments are highly dependent on the level of drilling in the CCA and on commodity prices, and thus, any change in the level of drilling or 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 $30.00 for oil and $5.00 for natural gas, it could have a material effect on our projected 2005 results. In this case, we would have to borrow additional money under our existing revolving credit facility, attempt to access the capital markets, or curtail the capital program. If drilling is curtailed or ended, future cash flows could be materially negatively impacted.
In addition to the possibility of a general market decline in oil and natural gas prices, a widening of the difference between the price we are paid and NYMEX prices, which we refer to as the differential, could have a material negative impact on our revenues. Due to a combination of higher prices and increased competition with foreign grades from both Canada and the Middle East, our differential to NYMEX oil widened in the second half of 2004. Early 2005 differentials to NYMEX oil also indicate a further widening. We expect our oil differential in 2005 to remain wider than 2004.
Expenses. The following table summarizes our expenses for the years ended December 31, 2004 and 2003:
Lease operations expense. Lease operations expense increased by $9.3 million in 2004 as compared to 2003. The increase in total lease operations expense resulted from an increase in production volumes as a result of our 2004 drilling program, the Elm Grove, Cortez and Overton acquisitions and our HPAI program, as well as an increase in the per BOE rate. The increase in our average per BOE rate was attributable to acquired properties with higher per BOE expenses and an increase in prices paid for outside services.
For 2005, we anticipate an increase in total lease operations expense on both an aggregate and a per BOE basis. We anticipate the overall increase due to a full year of production at our Cortez and Overton properties, as well as further implementation of the high-pressure air injection program. Currently, we are capitalizing the HPAI costs on the Little Beaver HPAI project, which will continue until the reservoir becomes fully pressurized. We expect the reservoir to become fully pressurized in 2005 and will begin expensing the costs of injecting air at that time. We have projected lease operations expense of $5.90 per BOE for 2005 as compared to $5.22 for 2004.
Production, ad valorem, and severance taxes. Production, ad valorem and severance taxes increased by $8.3 million in 2004 as compared to 2003. The increase in production, ad valorem, and severance taxes 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 hedges), production, ad valorem, and severance taxes decreased slightly from 9.4% to 9.0% from 2003 to 2004.
For 2005, 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 flat at 9.0% of wellhead revenues before hedging.
Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense increased by $15.0 million in 2004 as compared to 2003. The increase was primarily due to an increase in production as well as a increase in the per BOE rate. This rate increase was due to the acquisition of the Overton and Cortez properties, which had higher acquisition costs than our historical average, as well as higher drilling costs per BOE of reserves than our historical DD&A rate in certain areas.
We anticipate the total DD&A expense in 2005 will increase due to increased production and our planned 2005 capital expenditures of $223.0 million. We expect the invested capital to add barrels through the drill bit in 2005 at a cost higher than our historical DD&A rate. Assuming capital expenditures do not differ significantly from our budgeted amount, we expect our DD&A rate for 2005 to be approximately $7.00 per BOE. This rate could vary significantly based on actual capital expenditures, production rates, net profits interests, and any acquisitions that close in 2005. 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.
Exploration expense. Exploration costs increased in 2004 as we began a drilling exploration program in 2004. As previously discussed, we drilled a record number of wells in 2004, several of which were exploratory wells. We drilled 4 (3.88 net) non-productive exploratory wells at a cost of $2.1 million. This compares to 2003 when zero non-productive exploratory wells were drilled. Three of the exploratory dry holes were drilled in our Montana shallow gas area and one was drilled in the Barnett Shale in our Mid-Continent area. In addition to the increase in dry hole expense, additional exploration-related expenses were incurred in 2004 related to our exploration projects. We incurred abandonment and impairment of undeveloped leases costs of $0.7 million, delay rental expense of $0.2 million, seismic costs of $0.6 million, and other geological and geophysical expenses of $0.3 million.
For 2005, we expect exploration expense to be approximately $6.2 million as we continue our current exploration projects in the Mid-Continent and Montana shallow gas area. This amount could vary considerably, however, based on the success of these projects.
General and administrative (“G&A”) expense. G&A expense increased by $2.3 million in 2004 over 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 and costs associated with compliance with the Sarbanes-Oxley Act of 2002.
We have forecast approximately $14.0 million for general and administrative expenses in 2005 as compared to the $11.0 million incurred in 2004. The increase from 2004 is expected to result from increased staffing to manage our larger asset base, additional expenses related to compliance with the Sarbanes-Oxley Act of 2002, and higher directors and officers insurance costs. Additionally, we have
experienced increased competition for human resources from other companies within the industry that has increased the cost to hire and retain experienced industry personnel.
Non-cash stock based compensation expense. Non-cash stock based compensation expense increased from $0.6 million in 2003 to $1.8 million in 2004. 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 the years ended December 31, 2004, 2003, and 2002, we issued 68,071, 45,461, and 77,901 shares, respectively, of restricted stock to employees which depend only on continued employment for vesting. The following table illustrates by year of grant the vesting of shares which remain outstanding at December 31, 2004:
During the years ended December 31, 2004, 2003, and 2002, we issued 57,693, zero, and 51,427 shares of restricted stock to employees that not only depend on the passage of time and continued employment, but also on certain performance measures for their vesting. The following table illustrates by year of grant the vesting of shares which remain outstanding at December 31, 2004:
Deferred compensation of $3.4 million was reclassified within equity from additional paid in capital during the year ended December 31, 2004 in conjunction with the 2004 grants, and will be expensed over the related periods from the grant dates to the vesting dates.
Subsequent to December 31, 2004, we issued 164,703 shares of restricted stock to our employees as part of our annual incentive program. We have projected 2005 non-cash stock based compensation expense related to our restricted stock to be $1.4 million. This amount is dependent somewhat on fluctuations in our stock price because, as noted above, certain awards are accounted for as variable awards as they are based on achievement of certain performance measures.
Derivative fair value (gain) loss. The derivative fair value loss of $5.0 million in 2004 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, (gains) losses related to commodity derivatives not designated as hedges, and changes in the mark-to-market value of our fixed to floating interest rate swap.
In conjunction with the issuance of 83/8% 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 2004, a gain of $0.3 million related to this interest rate swap was recorded in ‘Derivative fair value (gain) loss.’ See “Note 12. Financial Instruments” to the accompanying consolidated financial statements.
The components of the derivative fair value (gain) loss reported for the year ended December 31, 2004 and 2003 are as follows (in thousands):
Ineffectiveness loss related to our contracts increased $4.2 million due primarily to an increase in oil differentials on our production in the CCA.
Other operating expense. Other operating expense increased $1.5 million in 2004 as compared to 2003. The increase in other operating expense is primarily attributable to $1.3 million increase in oil and natural gas transportation expense, $0.9 million increase in loss on sale of properties and $0.1 million increase in annual corporate taxes, offset by $0.8 million decrease in severance payments to former employees.
For 2005, we anticipate other operating expense to be approximately $6.4 million as compared to $5.0 million in 2004, which reflects the increased transportation costs associated with higher expected production volumes.
Interest expense. Interest expense for the year ended December 31, 2004 increased $7.3 million over 2003 due primarily to an increase in debt outstanding under our credit facility and the new 61/4% notes, offset slightly by a decrease in our weighted average interest rate from period to period. We incurred additional debt in 2004 to fund the Cortez and Overton acquisitions. The weighted average interest rate, net of hedges, for 2004 was 7.7% compared to 9.6% for 2003. This lower weighted average interest rate is the result of the issuance of $150 million aggregate principal amount of 61/4% senior subordinated notes in April 2004.
The following table illustrates the components of interest expense for 2004 and 2003 (in thousands):
Income tax expense. Income tax expense for 2004 increased $4.4 million over 2003. This increase is due primarily to the $23.8 million increase in income before income taxes from 2003 to 2004 offset by a decrease in our effective tax rate from 36.5% in 2003 to 33.0% in 2004. The decrease in effective income tax rate resulted from an incremental increase of $4.0 million for Section 43 credits ($6.1 million in Section 43 credits in 2004 as compared to $2.1 million in 2003) and the effect of the change in our state effective tax rate from 3.0% to 2.4% in 2004 due to changes in the asset mix and apportionment factors.
Comparison of 2003 to
Set forth below is our comparison of our results of operations for the year ended December 31, 2003 with our results of operations for the year ended December 31, 2002.
Revenues and Production. 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. The increase in oil production resulted from success through our drilling program, uplift from our HPAI program, and acquisitions 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 from July 31, 2003 (the date of acquisition) to December 31, 2003, the Elm Grove properties added 3,345 Mcfe per day to our average daily production for 2003.
Expenses. The following table summarizes our expenses for the years ended December 31, 2003 and 2002:
Lease operations expense. Lease operations expense increased by $7.2 million in 2003 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 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.
Production, ad valorem, and severance taxes. Production, ad valorem and severance taxes increased by $6.4 million in 2003 as compared to 2002. The increase in production, ad valorem, and severance taxes for the year ended December 31, 2003 as compared to 2002 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 hedges), production, ad valorem, and severance taxes increased slightly from 9.3% to 9.4% from 2002 to 2003.
Depletion, depreciation, and amortization (“DD&A”) expense. DD&A expense decreased by $1.0 million in 2003 as compared to 2002. Despite an increase in production, DD&A expense decreased in 2003 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 2002 to 2003.
General and administrative (“G&A”) expense. G&A expense increased by $2.5 million in 2003 as compared to 2002. 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.
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.
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.
In conjunction with the issuance of 83/8% 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 12. Financial Instruments” to the accompanying consolidated financial statements.
Other operating expense. Other operating expense for the year ended December 31, 2003 increased by approximately $1.4 million as compared to 2002. 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.
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 83/8% 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.
The following table illustrates the components of interest expense for 2003 and 2002 (in thousands):
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%.
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 gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
All capitalized costs associated with both development and exploratory wells are shown as ‘Development of oil and natural gas properties’ in the ‘Investing activities’ section of the Consolidated Statement of Cash Flows. If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the Consolidated Statement of Operations and shown as a non-cash adjustment to net income in the ‘Operating activities’ section of the Consolidated Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income at that time. 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. 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.
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. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Natural gas volumes are converted to equivalent barrels of oil at the rate of six Mcf to one barrel. See “Note 2. New Accounting Standards,” to the accompanying consolidated financial statements for a discussion of Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which we adopted as of January 1, 2003.
Unproved Properties. We adhere to Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider a combination of time and geologic and engineering factors to evaluate the need for impairment of these costs. Unproved properties had a net book value of $29.7 million and $0.9 million as of December 31, 2004 and 2003, respectively. We recorded a charge for unproved acreage impairment in the amount of $0.7 million, $0.4 million, and zero in 2004, 2003, and 2002, respectively.
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, Miller & Lents, Ltd., our independent reserve engineers, estimate our reserves once a year at December 31.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Cortez Oil & Gas, Inc. in April 2004 (see “Note 3, Acquisitions”). We test goodwill for impairment quarterly by applying a fair-value based test. We would recognize an impairment charge for any amount by which the carrying amount of goodwill exceeds its fair value. We tested goodwill for impairment and used discounted cash flows to establish fair values for the Company as a whole. The test indicated no impairment for 2004.
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 revenue. 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 to make higher net profit interest payments in 2005 and possibly beyond than we have in previous years, which directly impacts our revenues, production, reserves, and net income.
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. Natural gas revenue is recorded using the sales method of accounting whereby revenue is recognized as natural gas is sold rather than as it is produced. 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 price 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 43,010 Bbls and 46,622 Bbls at December 31, 2004 and 2003, respectively. Natural gas imbalances under-delivered to us at December 31, 2004 and December 31, 2003, were 540,000 MMBTU and 446,000 MMBTU, respectively.
Income Taxes
Section 43 Credits. Section 43 of the Internal Revenue Code (the “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 the project are
accurate, should the IRS disagree with our position, we would be required to record additional income tax expense to the extent income tax expense has previously been reduced related to the generation of Section 43 credits.
Effective Tax Rate. The Company’s effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax paying companies. Currently, our effective tax rate varies primarily as the amount of Section 43 income tax credits generated varies from period to period. These credits are generated by paying or incurring certain costs in connection with a qualifying enhanced oil recovery project, such as our current high-pressure air injection projects underway in the CCA. Our effective tax rate is also affected by changes in the allocation of property, payroll, and revenues between states in which we own property as rates vary from state to state.
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):
During the year ended December 31, 2004, 6,509 employee stock options and 9,236 shares of restricted stock that were issued and outstanding at December 31, 2003 were forfeited.
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.
We currently 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. 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 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 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.
New Accounting Standards
In December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25. SFAS 123(R) requires the measurement of all share-based payments to employees, including grants of employee stock options, using a fair-value-based method and the recording of expense in our Consolidated Statements of Operations. The accounting provisions of SFAS 123(R) are effective for reporting periods beginning after June 15, 2005. We are required to adopt SFAS 123(R) in the third quarter of 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. See “Stock-based Compensation” above for the pro forma net income and net income per share amounts, for fiscal 2002 through fiscal 2004, as if we had used a fair-value-based method similar to the methods required under SFAS 123(R) to measure compensation expense for employee stock incentive awards.
In December 2004, the FASB issued FASB Staff Position No. FAS 109-1 (“FAS 109-1”), “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004.” The American Jobs Creation Act introduces a new IRS code section, Section 199, which provides a deduction equal to 3% (increasing to 9% when fully phased-in in 2010) of taxable income from a qualified production activity. FAS 109-1 clarifies that this tax deduction should be accounted for as a special tax deduction in accordance with Statement 109, thereby reducing tax expense in the periods in which the deductions are deductible on the tax return. We do not expect the adoption of these new tax provisions to have a material impact on our consolidated financial position, results of operations, or cash flows.
Capital Resources, Capital Commitments, and Liquidity
Capital Resources and Capital Commitments
Our primary capital resources are net cash provided by operating activities and proceeds from financing activities. Our primary needs for cash are as follows:
•
Development, exploitation, and exploration 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
For 2005, our Board of Directors has approved the following $223.0 million capital budget, excluding potential proved property acquisitions (in thousands):
We analyze our inventory of capital projects based on $30.00 per Bbl and $5.00 per Mcf NYMEX prices. We do not assume any escalation of commodity prices when preparing our capital budget. If NYMEX prices trend downward below our base deck, we may reevaluate capital projects and may adjust the capital budgeted for development, exploitation, and exploration investments accordingly.
Development, Exploitation, and Exploration. Our capital expenditures for development, exploitation, and exploration during the years ended December 31, 2004, 2003, and 2002 were as follows (in thousands):
For 2005, we expect to invest $191.5 million in development, exploitation, and exploration projects.
High-Pressure Air Injection. 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. At Little Beaver, we completed the implementation of Phase I and Phase II during 2004. The reservoir is pressuring up in line with forecasts and we expect to see initial production uplift mid-year 2005. In 2002 we began Phase I of Little Beaver unit of CCA spending $6.6 million in development capital.
For 2005, we have budgeted $26.0 million for high-pressure air injection capital, primarily related to our Pennel program.
Acquisitions, Leasehold and Acreage Costs. Our capital expenditures for oil and natural gas proved property acquisitions during the years ended December 31, 2004, 2003, and 2002 were as follows (in thousands):
In 2004, we completed the Cortez and Overton acquisitions. In 2003, we completed an acquisition of interests in natural gas properties in the Elm Grove field in North Louisiana. In 2002, we completed the Central Permian acquisition from Conoco for approximately $50.1 million, and a second, follow-on acquisition of additional working interest for $8.3 million. Also in 2002, we acquired an interest in oil and natural gas properties in southeast Utah’s Paradox Basin.
We do not budget for acquisitions but we will continue to evaluate acquisition opportunities as they arise in 2005 with the same disciplined commitment to acquire assets that fit our portfolio and continue to create value. We will continue to pursue acquisitions of properties with similar upside potential to our current producing properties portfolio.
Because of the current high oil price environment, acquiring good quality oil and natural gas properties that are predictable, exploitable, and profitable is increasingly difficult. Success in the acquisition market depends largely on the level of competition in the marketplace and the availability of properties for sale.
Our current $223.0 million capital budget for 2005 does not include any funds for the development and exploitation of oil and natural gas properties that we may acquire during 2005. Our practice is to review our capital budget following a significant acquisition.
Our capital expenditures for leasehold and acreage costs during the years ended December 31, 2004, 2003, and 2002 totaled $33.9 million and $0.1 million, $0.4 million, respectively. Leasehold costs incurred in 2004 are higher than in the past primarily because of the Cortez, Overton, and Montana shallow gas acreage acquisitions during the year. Of the $33.9 million of capital expenditures for unproved property in 2004, $3.0 million and $18.4 million relate to the Cortez and Overton acquisitions respectively, $7.9 million relates to leases acquired in our Montana shallow gas area, and the remaining $4.6 million relates to unproved acreage spread over our other core areas.
For 2005, we expect to invest $4.0 million for the acquisition of leasehold and acreage costs primarily in our core areas.
Other General Property and Equipment. Our capital expenditures for other general property and equipment during the years ended December 31, 2004, 2003, and 2002 totaled $7.6 million, $1.5 million, and $0.7 million, respectively. Capital expenditures for other general property and equipment include aircraft, corporate leasehold improvements, computers, and various equipment.
For 2005, we expect to invest $1.5 million in other general property and equipment.
Working Capital. At December 31, 2004, our working capital was $(15.6) million while at December 31, 2003 working capital was $(0.1) million, a decrease of $15.5 million. At December 31, 2002, working capital was $12.5 million. The decrease from 2003 to 2004 was driven largely by an increase in our current derivative liability reflecting the current high commodity price environment. Higher working capital in 2002 was due to cash reserves held to maintain margin calls.
For 2005, we expect working capital to approximate $(29.5) million. Negative working capital is expected mainly due to fair values of our derivative contracts which obligations will be offset by cash flows from hedged production. 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 2005 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 $223 million for 2005. 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, cash on hand, and our existing credit agreement.
Contractual Obligations. The following table illustrates our contractual obligations and commercial commitments outstanding at December 31, 2004 (in thousands):
(1)
Amounts included in the table above include both principal and projected interest payments. See information presented in “Note 7. Indebtedness” to the accompanying consolidated financial statements for additional information regarding our long-term debt.
(2)
Derivative obligations represent liabilities for derivatives that were valued as of December 31, 2004. 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. We plan to continue in the normal course of business to hedge our exposure to fluctuating commodity prices. 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. In very limited circumstances, the Company may enter into derivative financial instruments to achieve other goals besides risk reduction. One example would be the use of a fixed to floating interest rate swap to offset interest expense on fixed rate debt. The Company weighs the increased risk of the instrument versus the potential cash flow savings before entering into any derivative instrument designed to achieve any goal other than risk reduction.
Counterparties. Our counterparties to hedging contracts include: BNP Paribas; Calyon; Deutsche Bank; Mitsui & Co.; Morgan Stanley; Shell Trading; Wachovia; and J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. At December 31, 2004 approximately 34%, 24%, 15%, and 15% of estimated hedged oil production was committed to Morgan Stanley, Deutsche Bank, J. Aron & Company, and Calyon, respectively. Approximately 63%, 16%, 11% and 10% of our estimated hedged gas production was contracted with J. Aron & Company, BNP Paribas, Mitsui & Co., and Morgan Stanley, respectively. Performance on all of our contracts with J. Aron & Company is guaranteed by its 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, 2004 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 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, 2004 was approximately $(58.9) million. As of December 31, 2004, the fair market value of our oil derivative contracts was $(39.4) million and the fair market value of our natural gas derivative contracts was $(13.0) million.
Oil Derivative Contracts at December 31, 2004
Natural Gas Derivative Contracts at December 31,
Subsequent to December 31, 2004, we entered into several additional oil and natural gas derivative contracts. We purchased oil put contracts for 4,000 barrels a day with various counterparties at $35.00 for the calendar year 2006 and entered into a basis swap contract for 500 barrels a day for the period of February to December 2005. In addition to the oil contracts, we purchased natural gas put contracts for 7,500 Mcf per day at $5.50 for the period of February 2005 to December 2005.
Interest rate sensitivity. At December 31, 2004, we had total long-term debt of $379.0 million. Of this amount, $150.0 million bears interest at a fixed rate of 83/8%, and $150.0 million bears at a fixed rate of 61/4%. The remaining outstanding long-term debt balance of $79.0 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, 2004, we had one outstanding interest rate swap. This swap does not qualify for hedge accounting as it swaps a 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,
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.
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, such as high-pressure air injection, 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 asset retirement obligations and 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 REGISTERED PUBLIC ACCOUNTING FIRM
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, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (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 the Company at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
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.”
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2005 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
March 7, 2005
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, a Delaware corporation (“Encore” or the “Company”), is a growing independent energy company engaged in the acquisition, development, exploitation, exploration, and production of onshore North American oil and natural gas reserves. Since the Company’s inception in 1998, Encore has sought to acquire high-quality assets with potential for upside through low-risk development drilling projects. Encore’s properties are currently located in four core areas: the Cedar Creek Anticline (“CCA”) in the Williston Basin of Montana and North Dakota; the Permian Basin of West Texas and Southeastern New Mexico; the Mid-Continent area, which includes the Arkoma and Anadarko Basins of Oklahoma, the ArkLaTx region of northern Louisiana and east Texas and the Barnett Shale of north Texas; and the Rockies, which includes non-CCA assets in the Williston and Powder River Basins of Montana, and the Paradox Basin of southeastern Utah.
2.
Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of all of our subsidiaries. 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 “Cash overdrafts” in the “Financing Activities” section of 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.
Properties and Equipment
Oil and Natural Gas Properties
The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive and nonproductive development wells are capitalized. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs associated with exploratory wells are initially capitalized pending determination of whether the well is economically productive or nonproductive.
All capitalized costs associated with both development and exploratory wells are shown as “Development of oil and natural gas properties” in the “Investing activities” section of the Consolidated Statement of Cash Flows. If an exploratory well does not find reserves or does not find reserves in a sufficient quantity as to make them economically producible, the previously capitalized costs are expensed in the Consolidated Statement of Operations and shown as a non-cash adjustment to net income in the “Operating activities” section of the Consolidated Statement of Cash Flows in the period in which the determination was made. If a determination cannot be made within one year of the exploration well being drilled and no other drilling or exploration activities to evaluate the discovery are firmly planned, all previously capitalized costs associated with the exploratory well are expensed and shown as a non-cash adjustment to net income at that time. Expenditures for redrilling or directional drilling in a previously
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. 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.
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. Capitalized costs are amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Natural gas volumes are converted to equivalent barrels of oil at the rate of six Mcf to one barrel.
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 after adjusting for fourth quarter production.
Unproved Properties
The Company adheres to Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. The Company considers a combination of time and geologic and engineering factors to evaluate the need for impairment of these costs. Unproved properties had a net book value of $29.7 million and $0.9 million as of December 31, 2004 and 2003, respectively. The Company recorded a charge for unproved acreage impairment in the amount of $0.7 million, $0.4 million, and zero in 2004, 2003, and 2002, respectively.
Other Property and Equipment
Other property and equipment are carried at cost. Depreciation and amortization are provided on a straight-line basis over their estimated useful lives, which range from three to ten years.
Goodwill
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Cortez Oil & Gas, Inc. in April 2004 (see “Note 3. Acquisitions”). The Company tests goodwill for impairment quarterly by applying a fair-value based test. The Company would recognize an impairment charge for any amount by which the carrying amount of goodwill exceeds its fair value. The Company tested goodwill for impairment and used discounted cash flows to establish fair values for the Company as a whole. The test indicated no impairment for 2004.
Capitalization of Interest
The Company does not capitalize interest related to our unevaluated oil and natural gas properties or any other long-lived assets.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Impairment
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. The Company tests for impairment on a quarterly basis. 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.
Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets.
SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of our oil and gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. See “Note 5, Asset Retirement Obligations” for more detail.
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. See “Note 11. Employee Benefit Plans” for more information.
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):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During the year ended December 31, 2004, 6,509 employee stock options and 9,236 shares of restricted stock that were issued and outstanding at December 31, 2003 were forfeited.
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. The following amounts represent weighted average values used in the model to calculate the fair value of the options granted during 2004, 2003, and 2002:
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.
In 2004, 29% and 27% of total oil and natural gas production was sold to Shell, and ConocoPhillips, respectively. In 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.
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 the Company’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 rather than as produced. 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. The Company’s net oil inventories in pipelines were 43,010 Bbls and 46,622 Bbls at December 31, 2004 and 2003, respectively. Natural gas imbalances under-delivered to the Company at December 31, 2004 and December 31, 2003, were 540,000 MMBTU and 446,000 MMBTU, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 Consolidated 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.
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) 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.
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 unrealized gains and losses on derivative financial instruments. The Company chooses to show comprehensive income annually 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 5. Asset Retirement Obligations.” Future changes in the assumptions used could have a significant impact on reported results in future periods.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
New Accounting Standards
In December 2004, the FASB issued Statement No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes APB 25. SFAS 123(R) requires the measurement of all share-based payments to employees, including grants of employee stock options, using a fair-value-based method and the recording of expense in our Consolidated Statements of Operations. The accounting provisions of SFAS 123(R) are effective for reporting periods beginning after June 15, 2005. We are required to adopt SFAS 123(R) in the third quarter of 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. See “Stock-based Compensation” above for the pro forma net income and net income per share amounts, for fiscal 2002 through fiscal 2004, as if we had used a fair-value-based method similar to the methods required under SFAS 123(R) to measure compensation expense for employee stock incentive awards.
In December 2004, the FASB issued FASB Staff Position No. FAS 109-1 (“FAS 109-1”), “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004.” The American Jobs Creation Act of 2004 (the “AJCA”) introduces a special 9% tax deduction on qualified production activities. FAS 109-1 clarifies that this tax deduction should be accounted for as a special tax deduction in accordance with Statement 109. Pursuant to the AJCA, Encore will not be able to claim this tax benefit until the first quarter of fiscal 2006. We do not expect the adoption of these new tax provisions to have a material impact on our consolidated financial position, results of operations or cash flows.
3.
Acquisitions
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 Resolute Natural Resources Company.
2003 Acquisitions
On July 31, 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. Subsequently, we have purchased several smaller interests in these properties. The original purchase was effective June 1, 2003. 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 located in the Elm Grove Field in Bossier Parish, Louisiana and are non-operated working interests ranging from 1% to 47% 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2004 Acquisitions
Cortez Acquisition. On April 14, 2004, the Company purchased all of the outstanding capital stock of Cortez Oil & Gas, Inc. (“Cortez”), a privately held, independent oil and natural gas company, for a total purchase price of $127.0 million, which includes cash paid to Cortez’ former shareholders of $85.8 million, the repayment of $39.4 million of Cortez’ debt, and transaction costs incurred of $1.8 million.
The acquired oil and natural gas properties are located primarily in the CCA of Montana, the Permian Basin of West Texas and Southeastern New Mexico and in the Mid-Continent area, including the Anadarko and Arkoma Basins of Oklahoma and the Barnett Shale north of Fort Worth, Texas. Cortez’ operating results are included in the Company’s Consolidated Statement of Operations beginning on April 1, 2004.
The calculation of the total purchase price and the estimated allocation as of December 31, 2004 to the fair value of net assets acquired at April 14, 2004, are as follows (in thousands):
The purchase price allocation resulted in $38.0 million of goodwill primarily as the result of the difference between the fair value of acquired oil and gas properties and their lower carryover tax basis, which resulted in deferred taxes of $36.9 million. Management believes the goodwill will be recovered through operating synergies resulting from the close proximity of the properties acquired to our existing operations, particularly the additional interest in the CCA and Permian properties acquired through the Cortez acquisition. None of the goodwill is deductible for income tax purposes.
Overton. On June 17, 2004, we completed the acquisition of natural gas producing properties and undeveloped leases in the Overton Field located in Smith County, Texas for $83.1 million. The Overton Field assets are in the same core area as our interests in Elm Grove Field and have similar geology. Overton operating results are included in our consolidated statement of operations for the period July through December 2004.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2004 (in thousands):
Our operating lease rental expense was approximately $3.5 million, $1.5 million, and $0.9 million in 2004, 2003, and 2002, respectively.
5.
Asset Retirement Obligations
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 of accounting change adjustment to record (1) a $4.0 million increase in the carrying values of proved properties, (2) a $2.1 million decrease in accumulated depletion, depreciation, and amortization, and (3) a $5.2 million increase in other non-current liabilities, and (4) 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):
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, 2004, the
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Company had $3.3 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 for the period from January 1, 2003 through December 31, 2004 (in thousands):
The pro-forma asset retirement obligation as of December 31, 2001 would have been $4.1 million, had the Company previously adopted SFAS 143 prior to January 1, 2001.
6.
Accounts Payable and Accrued Liabilities
Other current liabilities were as follows at December 31 (in thousands):
7.
Indebtedness
The following table details the Company’s indebtedness at December 31 (in thousands):
Senior Subordinated Notes
On June 25, 2002, the Company sold $150 million of 83/8% Senior Subordinated Notes maturing on June 15, 2012 (the “83/8% 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 83/8% Notes, after deducting debt issuance costs. The proceeds were used to repay and retire the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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).
On April 2, 2004, the Company issued $150.0 million of 61/4% Senior Subordinated Notes due April 15, 2014 (the “61/4% Notes” and together with the 83/8% Notes, the “Notes”). The Company received net proceeds of approximately $146.4 million after paying all costs associated with the offering. The net proceeds were used to fund the acquisition of Cortez Oil & Gas, Inc. and repay amounts outstanding under our revolving credit facility. The offering was made through a private placement. The 61/4% Notes were resold by the initial purchasers in transactions exempt from registration under Rule 144A and Regulation S. The privately placed notes were subsequently exchanged for registered notes with substantially identical terms.
Interest on the 61/4% Notes is paid semi-annually on April 15 and October 15. The indenture governing the 61/4% Notes contains certain affirmative, negative, and financial covenants, which 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 EBITDA, as defined, to interest expense ratio of 2.5 to 1.0. As of December 31, 2004, the Company was in compliance with all covenants in the indenture.
All of the Company’s subsidiaries are currently subsidiary guarantors of the Notes. Since (1) each subsidiary guarantor is 100% owned by the Company, (2) the Company has no assets or operations that are independent of its subsidiaries, (3) the subsidiary guarantees are full and unconditional and joint and several and (4) 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.
Revolving Credit Facility
On August 19, 2004, the Company entered into an amended and restated five-year senior secured revolving credit facility with a bank syndicate comprised of Bank of America, N.A. and other lenders. Availability under the amended and restated credit facility is determined through semi-annual borrowing base determinations and may be increased or decreased. The initial borrowing base is $400 million and may be increased to up to $750 million. The amended and restated credit facility matures on August 19, 2009. The amended and restated credit facility replaced the Company’s previous $300 million credit facility, which would have matured in June 2006.
The Company’s obligations under the amended and restated credit facility are guaranteed by its restricted subsidiaries and secured by a first priority-lien on substantially all of its proved oil and natural gas reserves and a pledge of the capital stock and equity interests of the Company’s restricted subsidiaries.
Amounts outstanding under the amended and restated credit facility are subject to varying rates of interest based on (1) the amount outstanding under the amended and restated credit facility in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. The following table summarizes the calculation of the various interest rates for both Eurodollar and base rate loans:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(a)
The LIBOR rate is equal to the rate determined by Bank of America, N.A. to be the British Bankers Association Interest Settlement Rate for deposits in dollars for a similar interest period (either one, two, three or six months, or such other period as selected by Encore, subject to availability at each lender).
(b)
The Base Rate is calculated as the highest of (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate” and (2) the federal funds effective rate plus 0.5%.
The borrowing base will be redetermined each June 1 and December 1, commencing June 1, 2005. The bank syndicate has the ability to request one additional borrowing base redetermination per year, and the Company is permitted to request two additional borrowing base redeterminations per year. Generally, if amounts outstanding ever exceed the borrowing base, the Company must reduce the amounts outstanding to the redetermined borrowing base within six months, provided that if amounts outstanding exceed the borrowing base as a result of any sale of the Company’s assets or permitted subordinated debt, the Company must reduce the amounts outstanding immediately upon consummation of the sale.
Borrowings under the amended and restated credit facility may be repaid from time to time without penalty.
The amended and restated credit facility contains certain affirmative, negative, and financial covenants; which include, but not limited to, (1) limitations on the incurrence of additional debt, payment of dividends, repurchases of the Company’s common stock, asset dispositions and restricted payments, (2) maintenance of a 1.0 to 1.0 current ratio, and (3) maintenance of EBITDA, as defined, to interest expense ratio of 2.5 to 1.0. As of December 31, 2004, the Company was in compliance with all covenants in the amended and restated credit facility.
As of December 31, 2004, The Company had $79.0 million outstanding under the facility. This reflects an increase of $50.0 million to the outstanding balance under the facility at December 31, 2003.
The Company incurs a commitment fee on the unused portion of the facility determined based on the ratio of borrowings to the borrowing base in effect on such date. The following table summarizes the calculation of the Company’s commitment fee:
During 2004 and 2003, the weighted average interest rates for our revolving credit facilities were 6.6% and 7.2%, respectively.
Letters of Credit
The Company had $30.4 million and zero of outstanding letters of credit at December 31, 2004 and 2003, respectively. These letters of credit are posted primarily with two counterparties to the Company’s commodity derivative contracts and are used in lieu of cash margin deposits with those counterparties.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Long-Term Debt Maturities
The following table illustrates the Company’s long-term debt maturities at December 31, 2004 (in thousands):
Consolidated cash payments for interest were $21.4 million, $16.2 million, and $13.2 million, respectively, for 2004, 2003, and 2002.
During 2004 and 2003, the weighted average interest rate for total indebtedness, including our Notes, revolving credit facility, letters of credit, and related miscellaneous fees was 7.7% and 9.6%, respectively.
8.
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 Consolidated Statements of Operations were attributed to the following items (in thousands):
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):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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):
Cash income tax payments in the amount of $3.7 million and $1.5 million were made in 2004 and 2003. No cash income tax payments were made in 2002. If unused, $0.3 million of the Section 43 credits will expire in 2023 and $6.1 million in 2024. Additionally, the Company recognized in equity a benefit resulting from the reduction in income taxes payable related to the exercise of employee stock options in
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the amount of $1.4 million, $0.1 million, and zero in the years ended December 31, 2004, 2003, and 2002, respectively.
Taxes Other than Income Taxes
Taxes other than income taxes were comprised of the following (in thousands):
9.
Stockholders’ Equity
Public Offerings of Common Stock
On November 13, 2003, the Company priced a public offering of 8.0 million shares of the Company’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 the Company’s common stock from J.P. Morgan Partners (SBIC), LLC and 2,193,357 shares from Warburg Pincus Equity Partners L.P. at a price of $19.3775 per share. The 9.06 million shares the Company purchased were retired upon repurchase. The Company’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.
On June 8, 2004, we priced a public offering of 2.0 million shares of our common stock at a price to the public of $26.95 per share. The shares were sold under a shelf registration statement, that had been declared effective by the Securities and Exchange Commission in August 2003. The net proceeds of the offering, after underwriting discounts and commissions, and other related expenses were approximately $52.9 million. The Company used the net proceeds of this offering to repay indebtedness under its revolving credit facility and for general corporate purposes.
Shelf Registration on Form S-3. On June 30, 2004, the Company filed a “shelf” registration with the SEC on Form S-3 (Registration No. 333-117036). Using this process, we may offer common stock, preferred stock, senior debt and subordinated debt in one or more offerings with a total initial offering price of up to $500 million.
Common Stock Option Exercises
During the years ended December 31, 2004, 2003 and 2002, employees of the Company exercised 202,577, 145,727 and 3,666 options, respectively. The Company received proceeds from the option exercises of $2.8 million, $2.0 million, and $0.1 million in the years ended December 31, 2004, 2003, and 2002, respectively, related to these option exercises.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Preferred Stock
The Company’s authorized capital stock includes 5,000,000 shares of preferred stock, 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.
10.
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.
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, 2004 and December 31, 2003. 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.
11.
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
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
employee contributions, totaled $0.9 million in 2004, $0.5 million in 2003, and $0.5 million in 2002. 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 and stockholders approved the 2000 Incentive Stock Plan (the “Plan”). The original plan was amended and restated effective March 18, 2004. 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 for issuance pursuant to the Plan is 3,000,000. As of December 31, 2004, there were 1,361,438 shares remaining under the Plan. The Plan provides for the granting of cash awards, incentive stock options, non-qualified stock options, restricted stock, and stock appreciation rights at the discretion of the Compensation Committee of the Company’s Board of Directors.
The Plan contains the following individual limits:
•
an employee may not be awarded more than 150,000 shares of common stock in any calendar year;
•
a nonemployee director may not be awarded more than 10,000 shares of common stock in any calendar year; and
•
an employee may not receive awards consisting of cash (including cash awards that are granted as performance awards) in respect of any calendar year having a value determined on the grant date in excess of $1 million.
The Plan also permits nonqualified stock options at 85% of fair value.
All options that have been 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 2004, 2003, and 2002:
(a)
During 2004 and 2003, 25,000 and 15,000 of the options, respectively, were granted to non-employee directors. The weighted average fair value of individual options granted in 2004 and 2003 was $10.31 and $6.38, respectively.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Additional information about common stock options outstanding and exercisable at December 31, 2004 is as follows:
During the years ended December 31, 2004, 2003, and 2002, we issued 68,071, 45,461, and 77,901 shares, respectively, of restricted stock to employees which depend only on continued employment for vesting. The following table illustrates by year of grant the vesting of shares which remain outstanding at December 31, 2004:
During the years ended December 31, 2004, 2003, and 2002, we issued 57,693, zero, and 51,427 shares of restricted stock to employees that not only depend on the passage of time and continued employment, but on certain performance measures, for their vesting. The following table illustrates by year of grant the vesting of shares which remain outstanding at December 31, 2004:
Deferred compensation of $3.4 million was reclassified within equity from additional paid in capital during the year ended December 31, 2004 in conjunction with the 2004 grants, and will be expensed over the related periods from the grant dates to the vesting dates.
Subsequent to December 31, 2004, we issued 164,703 shares of restricted stock to our employees as part of our annual incentive program.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
12.
Financial Instruments
The following table sets forth the book value and estimated fair value of the Company’s financial instruments as of the dates indicated (in thousands):
The book value of cash and cash equivalents approximates fair value because of the short maturity of these instruments. The fair values of our Notes were determined using their open market quote as of December 31, 2004. The difference between book value and fair value represents the premium or discount on that date. The book value of the revolving credit 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, 2004 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 a 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 Consolidated Statement of Operations.
In order to more effectively hedge the cash flows received on our oil and natural gas production, the Company enters into financial instruments, commonly called basis swaps, 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, 2004, the mark-to-market value of these contracts was $0.4 million.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables summarize our open commodity derivative positions designated as cash flow hedges as of December 31, 2004:
Oil Hedges at December 31, 2004
Natural Gas Hedges at December 31, 2004
As a result of all of our hedging transactions for oil and natural gas, we recognized a pre-tax reduction in revenues of approximately $38.0 million, $15.3 million, and $5.2 million, in 2004, 2003, and 2002, respectively. Based on the fair value of our hedges at December 31, 2004, our unrealized pre-tax loss recorded in ‘other comprehensive income’ related to outstanding hedges was $45.2 million for oil and $13.7 million for natural gas. Of the total deferred hedge loss at December 31, 2004 related to commodity contracts, $28.1 million, $19.5 million, $11.3 million relate to 2005, 2006, and 2007 contracts, respectively.
Interest Rate Derivatives
As discussed in “Note 7. Indebtedness,” in conjunction with the sale of the 83/8% 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 as of June 25, 2002. 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):
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $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 Consolidated Statements of Operations.
The following table summarizes the Company’s only remaining interest rate swap contract at December 31, 2004:
We recognized in interest expense a pre-tax loss of approximately $0.5 million, $1.9 million, and $1.6 million in 2004, 2003, and 2002, respectively. Additionally, $0.3 million was recognized in “Derivative fair value (gain) loss” in 2004 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, 2004 due to the 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: BNP Paribas; Calyon; Deutsche Bank; Mitsui & Co.; Morgan Stanley; Shell Trading; Wachovia; and J. Aron & Company, a wholly-owned subsidiary of Goldman, Sachs & Co. At December 31, 2004, approximately 34%, 24%, 15%, and 15% of the Company’s estimated hedged oil production was committed to Morgan Stanley, Deutsche Bank, J. Aron & Company, and Calyon, respectively. At December 31, 2004, approximately 63%, 16%, 11% and 10% of the Company’s hedged gas production was contracted with J. Aron & Company, BNP Paribas, Mitsui & Co., and Morgan Stanley, respectively. Performance on all of the Company’s contracts with J. Aron & Company was guaranteed by its parent, Goldman, Sachs & Co. The Company feels the credit-worthiness of the current counterparties is sound and the Company does 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, the Company enters into master netting agreements with significant counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and the Company. Instead of treating separately each financial transaction between our counterparty and the Company, the master netting agreement enables Encore’s counterparty and the Company 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 Encore. Second, default by counterparty under one financial trade can trigger rights 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.
13.
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
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
With the Cortez acquisition (see “Note 3. Acquisitions”), the Company acquired an Enron derivative contract. To negate any adverse effects of this contract, the Company entered into another contract with opposite terms.
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 receivable, the Company is not aware of any conditions which warrant an allowance or write-off of a receivable or derivative position.
14.
Related Party Transactions
The Company paid $0.3 million to Hanover Compression Company in 2004 for compression services. Mr. I. Jon Brumley, the Company’s Chairman, Director, and CEO, also serves as a director of Hanover Compressor Company.
15.
Capitalized Costs and Costs Incurred Relating to Oil and Natural Gas Producing Activities
The capitalized cost of oil and natural gas properties at December 31, 2004 and 2003 are as follows (in thousands):
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2002, the Company’s acquisition cost incurred on a pro-forma basis would have been increased by $0.7 million for the year ended December 31, 2002. The effect on the Company’s development cost incurred on a pro-forma basis would have been insignificant.
SUPPLEMENTAL INFORMATION (unaudited)
16.
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 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, 2004, 2003, and 2002 were $43.46, $32.55, and $31.20 per barrel, respectively, for oil and $6.19, $5.83, and $4.79 per Mcf, respectively, for natural gas. The net profits interest on our Cedar Creek Anticline properties has been
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
deducted from future cash inflows in the calculation of Standardized Measure. The Company’s reserve and production quantities from our Cedar Creek Anticline properties 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 as of the dates indicated:
Encore is committed to sell at least 2,500 barrels of oil per day at a floating market price through 2009.
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 as of the dates indicated:
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Primary changes in the Standardized Measure of discounted estimated future net cash flows (in thousands) are as follows for the periods indicated:
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
17.
Selected Quarterly Financial Data (unaudited)
The following table sets forth selected quarterly financial data for the years ended December 31, 2004 and 2003:
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that, as of December 31, 2004, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in applicable rules and forms.
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2004, management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2004, based on those criteria.
Ernst & Young, LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual report on Form 10-K, has issued an attestation report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. The report, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, is included in this Annual Report on Form 10-K, Item 9A. under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.”
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
To the Board of Directors and Shareholders of
Encore Acquisition Company:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that Encore Acquisition Company and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management of the Company is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the internal control over financial reporting of the Company based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by the COSO. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 7, 2005 expressed an unqualified opinion on thereon.
/s/ Ernst & Young LLP
Fort Worth, Texas
March 7, 2005
Changes in Internal Control over Financial Reporting
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.
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The information required in response to this item is set forth under the captions “Corporate Governance Principles and Board Matters - Governance Framework,” “Corporate Governance Principles and Board Matters - Board Structure and Composition,” “Proposals to be Voted On - Proposal No. 1 - Election of Directors,” “Executive Officers” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement for the 2005 annual meeting of stockholders 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). We will post on our web site any amendments to the Code of Business Conduct and Ethics or waivers of the Code of Business Conduct and Ethics for directors and executive officers.
Item 11.
Item 11.
Executive Compensation
The information required in response to this item is set forth under the captions “Corporate Governance Principles and Board Matters - Compensation of Directors” and “Executive Compensation” (other than the information under the caption “Compensation Committee Report On Executive Compensation”) in the Company’s definitive proxy statement for the 2005 annual meeting of stockholders 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 under the caption “Security Ownership of Certain Beneficial Owners and Management” in the Company’s definitive proxy statement for the 2005 annual meeting of stockholders and is incorporated herein by reference.
The following table sets forth information about the Company’s common stock that may be issued under the Company’s equity compensation plans as of December 31, 2004:
(1)
The 2000 Incentive Stock Plan is the Company’s only equity compensation plan.
(2)
Excludes 272,922 shares of restricted stock.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The information required in response to this item is set forth under the caption “Certain Relationships and Related Transactions” in the Company’s definitive proxy statement for the 2005 annual meeting of stockholders 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 under the caption “Principal Accountant Fees and Services” in the Company’s definitive proxy statement for the 2005 annual meeting of stockholders and is incorporated herein by reference.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this Report:
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) 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
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 9th day of March, 2005.
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 9, 2005.