EXHIBIT 99.2
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This Current Report on Form 8-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, see “Quantitative and Qualitative Disclosures About Market Risk - Cautionary Statement for Purposes of the Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws” of this Form 8-K.
This report contains consolidated financial statements of the Company that have been reclassified to reflect the adoption of EITF 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” and the reporting of discontinued operations for the sale of oil and gas properties in 2003.
Generally, no attempt has been made in the following discussion to modify or update other disclosures, except as required to reflect the effects of the above items.
CRITICAL ACCOUNTING POLICIES AND PRACTICES
The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. The Company’s estimates of crude oil and natural gas reserves are the most significant. All of the reserve data in this Form 8-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
The Company accounts for its crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by Company engineers. Through December 31, 2002, estimated future restoration and abandonment costs are recorded by charges to depreciation, depletion and amortization (“DD&A”) expense over the productive lives of the related properties.
The Company generally recognizes revenue when the product is delivered to a third-party purchaser. The Company follows the entitlements method of accounting for its natural gas imbalances. Natural gas imbalances occur when the Company sells more or less natural gas than it is entitled to under its ownership percentage of total natural gas production. Any excess amount received above the Company’s share is treated as a liability. If less than the Company’s entitlement is received, the underproduction is recorded as a receivable.
The Company, directly or through its subsidiaries, from time to time, uses various derivative arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars and other contractual arrangements. The Company accounts for its derivative arrangements under Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and has elected to designate its derivative arrangements as cash flow hedges.
Other significant items subject to estimates and assumptions include the carrying amount of property, plant and equipment; valuation allowances for receivables, inventories and deferred income tax assets; environmental liabilities; valuation of derivative instruments; and assets and obligations related to employee benefits. Actual results could differ
1
from those estimates. Management believes it is necessary to understand the Company’s significant accounting policies, “Financial Statements and Supplementary Data—Note 1 - Summary of Significant Accounting Policies” of this Form 8-K, in order to understand the Company’s financial condition, changes in financial condition and results of operations.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
The Company’s net cash provided from operations in 2002 was lower than 2001 due to lower natural gas prices and decreased gas production volumes, offset partially by increased oil production volumes. Net cash from operating activities per BOE of total production are shown in the chart below.
The crude oil price received by the Company in 2002 decreased one percent from 2001 and the natural gas price received by the Company decreased 26 percent in 2002 from the price received in 2001. In 2001, the Company’s crude oil price increased one percent and the natural gas price increased five percent compared to 2000.
The Company owns a 45 percent interest in AMPCO through its ownership in AMCCO. Prior to January 2002, AMCCO was a 50 percent owned joint venture that owned an indirect 90 percent interest in AMPCO, which completed construction of a methanol plant in Equatorial Guinea in the second quarter of 2001. During 1999, AMCCO issued $125 million Series A-1 and $125 million Series A-2 senior secured notes due December 15, 2004 to fund the remaining construction payments. The Company includes the $125 million Series A-2 senior notes in its balance sheet. On January 2, 2002, the Company’s partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a component of the partner’s sale of its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay in full AMCCO’s $125 million Series A-1 Notes on January 28, 2002 and to make a distribution to the Company’s partner. The terms of the $125 million Series A-2 Notes remain unchanged. The plant construction started during 1998 and initial production of commercial grade methanol commenced May 2, 2001. The total costs of the plant and supporting facilities as of December 31, 2002 were $417 million, with the Company responsible for $208.5 million. During 2002, the Company recorded costs of $7 million toward the project.
During 2002, $544 million was spent on acquisition, exploration and development projects, $7 million on the methanol project, $51 million on the Machala power project in Ecuador and $3 million for various other projects for total expenditures of $605 million. The 2003 capital expenditures budget is approximately $510 million.
The Company’s current ratio (current assets divided by current liabilities) was .66:1 at December 31, 2002, compared with .92:1 at December 31, 2001. The decrease in the current ratio was due to a $57.8 million decrease in cash and short-term investments coupled with an $81.8 million increase in accounts payable.
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Financing
The Company’s total long-term debt, net of unamortized discount, at December 31, 2002, was $977 million compared to $961 million at December 31, 2001. The ratio of debt-to-book capital (defined as the Company’s total debt plus its equity) was 50 percent at December 31, 2002, and 50 percent at December 31, 2001.
(in thousands) |
| Payments Due by Period |
| |||||||||||||
| Total |
| Less Than |
| 1 to 3 |
| 4 to 5 |
| After 5 |
| ||||||
Long-term debt |
| $ | 1,025,246 |
| $ | 41,919 |
| $ | 153,327 |
| $ | 380,000 |
| $ | 450,000 |
|
Drilling obligations |
| 118,211 |
| 116,411 |
| 1,800 |
|
|
|
|
| |||||
Total contractual cash obligations |
| $ | 1,143,457 |
| $ | 158,330 |
| $ | 155,127 |
| $ | 380,000 |
| $ | 450,000 |
|
The Company’s long-term debt, net of current portion, is comprised of:
• $250 million of 8% Senior Notes Due 2027
• $100 million of 7 1/4% Notes Due 2097
• $100 million of 7 1/4% Notes Due 2023
• $380 million on the $400 million credit facility based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating, maturing in 2006. The interest rate at December 31, 2002 was 2.47 percent. The interest rate at December 31, 2001 was 3.0 percent.
• $125 million of 8.95% Series A-2 Notes on the AMCCO debt, payable in 2004.
• $20.4 million on the Israel debt based upon the London Interbank Offering Rate (“LIBOR”) plus 75 basis points, payable in 2004. The interest rate at December 31, 2002 was 2.18 percent. There was no outstanding Israel debt at December 31, 2001.
• $7.9 million of the 6.25% Aspect acquisition note, payable in 2004
• ($6.2) million unamortized discount
The Company entered into a new $400 million five-year credit agreement on November 30, 2001 with certain commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million borrowed against this credit agreement, which has a maturity date of November 30, 2006. For more information, see “Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 8-K.
The Company also entered into a new $200 million 364-day credit agreement on November 27, 2002 with certain commercial lending institutions which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 62.5 to 150 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there were no amounts outstanding under this credit agreement. The agreement has a maturity date of November 26, 2003 for the revolving commitment and a maturity date of November 25, 2004 for the term commitment that includes any balance remaining after the revolving commitment matures. For more information, see “Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 8-K.
Financial covenants on both the $400 million and $200 million credit facilities include the following: (a) the ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense (“EBITDAX”) to total interest expense for any consecutive period of four fiscal quarters ending on the last day of a fiscal quarter may not be less than 4.0 to 1.0; (b) the total debt to capitalization ratio, expressed as a percentage, may not exceed 60 percent at any time; and (c) the total asset value of the Company’s restricted subsidiaries may not be less than $800 million at any time.
The Company had no short-term borrowings outstanding on December 31, 2002. The Company had a $25 million short-term note payable outstanding December 31, 2001, which was repaid January 28, 2002. The note was an uncommitted facility with an interest rate of 3.25 percent for the period December 28, 2001 to January 28, 2002.
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Other
The Company has paid quarterly cash dividends of $.04 per share since 1989. For more information, see “Subsequent Events” of this Form 8-K.
The Company’s Board of Directors, in February 2000, authorized a repurchase of up to $50 million in the Company’s common stock. In the first quarter of 2000, the Company repurchased approximately $30 million of common stock. The 2000 repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded from the Company’s current cash flow. On September 17, 2001 the Company’s Board of Directors approved an expansion of the original repurchase program from $50 million to $100 million. During the fourth quarter of 2001, in conjunction with the expanded repurchase program, the Board approved a stock repurchase forward program. Under the stock repurchase forward program, one of the Company’s banks purchased approximately $35 million of the Company’s stock or 1,044,454 shares on the open market during the first quarter of 2002.
The program was scheduled to mature in January 2003 but has been extended to January 2004. Under the provisions of the agreement with the bank, the Company can choose to either purchase the shares from the bank, issue additional shares to the bank to the extent that the share price has decreased, pay the bank a net amount of cash to the extent that the share price has decreased, or receive from the bank a net amount of cash to the extent that the share price has increased. The bank has the right to terminate the agreement prior to the maturity date if the Company’s share price decreases by 50 percent (to $16.77 per share) or if the Company’s credit rating is downgraded below BBB- (S&P) or Baa3 (Moody’s). If either event occurs and the bank exercises its right to terminate, the Company still retains the right to settle in cash or additional shares. The agreement limits the number of shares to be issued by the Company to 14,000,000 additional shares. Amounts paid or received related to the change in share price will be an addition or reduction to the Company’s capital in excess of par value. As of December 31, 2002, the fair value of the Company’s obligation under the contract would be an obligation to pay approximately $36.1 million to the bank (and hold the shares as treasury stock), or the bank would return 81,946 shares of Company stock to the Company, or the bank would pay $3.1 million to the Company. In June 2003, the Company and the bank amended the agreement to delete the provisions that allowed the Company to net settle the contract, and in December 2003, the Company paid the obligation in full. See also “Subsequent Events” of this Form 8-K.
The Company has sold a number of non-strategic crude oil and natural gas properties over the past three years. Total amounts of crude oil and natural gas reserves associated with the 2002 and 2000 dispositions were .7 MMBbls of oil and 20.3 Bcf of gas and 1.2 MMBbls of oil and 4.8 Bcf of gas, respectively. There were no significant sales of oil or gas properties in 2001. The Company believes the disposition of non-strategic properties furthers the goal of concentrating its efforts on strategic properties.
During 2002, the Company paid $7 million related to certain operating contingencies that had previously been accrued.
The Financial Accounting Standards Board (“FASB”) issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” in June 1998. The Statement established accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders’ equity as other comprehensive income until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this statement did not have a material impact on the Company’s results of operations or financial position.
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RESULTS OF OPERATIONS
Net Income and Revenues
The Company’s income from continuing operations for 2002 was $10.9 million, a decrease of $76.5 million from 2001. The decrease was due primarily to a $151.9 million decrease in natural gas sales, offset by a $43.2 million increase in crude oil sales. The decrease in net income for 2001 compared to 2000 was due to a $61.2 million increase in dry hole expense coupled with a $48.8 million increase in depreciation, depletion and amortization, offset by a $36.4 million increase in crude oil sales coupled with a $43.1 million increase in natural gas sales.
Natural Gas Information
Natural gas revenues decreased 30 percent in 2002 due to a 26 percent decrease in the average natural gas price coupled with a four percent decrease in natural gas production. In the United States, natural gas production decreased nine percent due to reduced drilling activity, natural decline rates for properties in the Gulf of Mexico and the onshore Gulf Coast region, as well as temporary shut-ins related to Hurricanes Isidore and Lili, coupled with a 24 percent decrease in the average natural gas price. In the North Sea, natural gas revenues decreased 15 percent due to an 11 percent decrease in the average natural gas price coupled with a five percent decrease in natural gas production. In Equatorial Guinea, natural gas revenues increased 39 percent due to the full year of operations of the methanol plant.
Natural gas revenues for 2001 increased nine percent due to a six percent increase in natural gas production coupled with a five percent increase in the average natural gas price compared to 2000. The methanol plant in Equatorial Guinea began operations on May 2, 2001, which accounted for the increased natural gas production compared to 2000.
The table below depicts average daily natural gas production in Mcf from continuing operations by area for the last three years.
|
| 2002 |
| 2001 |
| 2000 |
|
|
|
|
|
|
|
|
|
United States |
| 282,984 |
| 311,913 |
| 307,862 |
|
North Sea |
| 16,991 |
| 17,830 |
| 23,676 |
|
Equatorial Guinea |
| 34,382 |
| 24,488 |
| 2,572 |
|
Other International |
| 8,799 |
| 1,651 |
| 1,970 |
|
Total from continuing operations | 343,156 | 355,882 | 336,080 | ||||
Discontinued operations |
| 44,467 |
| 66,562 |
| 70,239 |
|
Total |
| 387,623 |
| 422,444 |
| 406,319 |
|
Natural gas production during 2002 ranged from a low of 307.4 MMcfpd in May, to a high of 379.9 MMcfpd in January. Natural gas accounted for 57 percent of the Company’s total natural gas and crude oil revenues in 2002.
5
2002 Daily Production by Quarter | ||
|
|
|
Natural Gas |
| Crude Oil |
|
|
|
Crude Oil Information
Crude oil revenues increased 19 percent during 2002 due to a 15 percent increase in production coupled with a one percent decrease in the average crude oil price. In the North Sea, crude oil revenues increased 80 percent due to a full year of production from the Hanze field, the commencement of production from the Hannay field in March 2002 and an eight percent increase in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 18 percent due to a 14 percent increase in production from the Alba field, coupled with a four percent increase in the average crude oil price.
Crude oil revenues increased 19 percent in 2001, compared to 2000, due to a 25 percent increase in production and a one percent increase in the average price received for 2001. In the North Sea, crude oil revenues increased 136 percent due to the commencement of production from the Hanze field in August 2001, offset by a 10 percent decrease in the average crude oil price. In Equatorial Guinea, crude oil revenues increased 52 percent due to an 85 percent increase in production from the Alba field, offset by a 17 percent decline in the average price.
The table below depicts average daily crude oil production in Bbls for continuing operations by area for the last three years.
|
| 2002 |
| 2001 |
| 2000 |
|
United States |
| 14,196 |
| 14,069 |
| 14,158 |
|
North Sea |
| 7,847 |
| 4,688 |
| 1,787 |
|
Equatorial Guinea |
| 5,259 |
| 4,620 |
| 2,497 |
|
Other International |
| 2,821 |
| 2,739 |
| 2,502 |
|
Total from continuing operations |
| 30,123 |
| 26,116 |
| 20,944 |
|
Discontinued operations |
| 3,914 |
| 4,545 |
| 4,861 |
|
Total |
| 34,037 |
| 30,661 |
| 25,805 |
|
Crude oil production during 2002 ranged from a low of 27,146 Bopd in July, to a high of 32,467 Bopd in April. Crude oil accounted for 43 percent of the Company’s total natural gas and crude oil revenues in 2002.
Derivatives and Hedging Activities
The Company, directly or through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties and believes that
6
losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company’s crude oil and natural gas production are recorded in crude oil and natural gas sales and royalties. For more information, see “Quantitative and Qualitative Disclosures About Market Risk” of this Form 8-K.
Costs and Expenses
Crude oil and natural gas operations expense, consisting of lease operating expense, workover expenses, production taxes and other related lifting costs, remained flat in 2002 compared to 2001. In the North Sea, operations expense increased 78 percent due to a full year of production operations from the Hanze field and the commencement of operations from the Hannay field in March 2002. In Equatorial Guinea, operations expense increased 45 percent due to the increased production from the Alba field. Domestic operations expense decreased $6.2 million during 2002 offsetting the international increases. Crude oil and natural gas operations expense increased 12 percent overall in 2001 from 2000. In the North Sea, operations expense increased 16 percent due to the commencement of operations of the Hanze field in August 2001. In Equatorial Guinea, operations expense increased 57 percent due to the commencement of natural gas deliveries to the methanol plant in May 2001. Included in operations expense were workover costs of $6.8 million, $12.2 million and $16.6 million for 2002, 2001 and 2000, respectively. The workovers increased operations expense in such periods by $.04, $.07 and $.10 per Mcfe, respectively.
|
In 2002, DD&A expense increased slightly compared to 2001. In the North Sea, DD&A expense increased 71 percent due to a full year’s production of the Hanze field. In Equatorial Guinea, DD&A expense increased 50 percent due to the results of the field expansion, which included a full year of natural gas sales to the methanol plant. The unit rate of DD&A per BOE was $7.47 in 2002.
In 2001, DD&A expense increased 26 percent overall compared to 2000. In the United States, DD&A expense increased 25 percent due to increased development costs incurred in the Gulf of Mexico to stabilize production volumes. In the North Sea, DD&A expense increased 34 percent due to the commencement of production from the Hanze field in August 2001. In Equatorial Guinea, DD&A expense increased 186 percent due to the commencement of natural gas sales to the methanol plant in May 2001. The unit rate of DD&A per BOE was $7.61 in 2001.
Through December 31, 2002, the Company provided for the cost of future liabilities related to restoration and dismantlement costs for offshore facilities. This provision is based on the Company’s best estimate of such costs to be incurred in future years based on information from the Company’s engineers. These estimated costs were provided through charging DD&A expense using a ratio of production divided by reserves multiplied by the estimated costs to dismantle and restore. The Company adopted SFAS No. 143 on January 1, 2003 and will recognize, as the fair value of asset retirement obligations, $99.7 million related to the United States and $10.0 million related to the North Sea. The Company’s accumulated provision for future dismantlement and restoration cost was $84.1 million at
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December 31, 2002, $80.0 million at December 31, 2001 and $79.7 million at December 31, 2000. The Company has not determined the cumulative effect of adoption of this standard. Total estimated future dismantlement and restoration costs of $206.6 million, which consists of $188.7 million for the United States and $17.9 million for the North Sea, are included in future production and development costs for purposes of estimating the future net revenues relating to the Company’s proved reserves. For more information, see “Financial Statements and Supplementary Data—Note 1 - Summary of Significant Accounting Policies” of this Form 8-K.
Crude oil and natural gas exploration expense consists of dry hole expense, unproved lease amortization, seismic and other miscellaneous exploration expense, including lease rentals and exploration staff. The table below depicts the exploration expense by area for the last three years.
(in thousands) |
| 2002 |
| 2001 |
| 2000 |
| |||
United States |
|
|
|
|
|
|
| |||
Dry hole expense |
| $ | 64,449 |
| $ | 54,810 |
| $ | 37,281 |
|
Unproved lease amortization |
| 19,426 |
| 15,112 |
| 15,675 |
| |||
Seismic |
| 14,282 |
| 13,328 |
| 17,794 |
| |||
Other |
| 22,538 |
| 17,242 |
| 9,617 |
| |||
United States Total Exploration Expense |
| $ | 120,695 |
| $ | 100,492 |
| $ | 80,367 |
|
North Sea |
|
|
|
|
|
|
| |||
Dry hole expense |
| $ | 544 |
| $ | 28,992 |
| $ | 17 |
|
Unproved lease amortization |
| 178 |
| 1,725 |
|
|
| |||
Seismic |
| 827 |
| 2,209 |
| 239 |
| |||
Other |
| 3,661 |
| 2,024 |
| 1,140 |
| |||
North Sea Total Exploration Expense |
| $ | 5,210 |
| $ | 34,950 |
| $ | 1,396 |
|
Other International including Israel and Equatorial Guinea |
|
|
|
|
|
|
| |||
Dry hole expense |
| $ | 16,403 |
| $ | 15,882 |
| $ | 1,165 |
|
Unproved lease amortization |
| 1,650 |
| 376 |
| 400 |
| |||
Seismic |
| 5,383 |
| 70 |
| 705 |
| |||
Other |
| 1,360 |
| 326 |
| 835 |
| |||
Other International Total Exploration Expense |
| $ | 24,796 |
| $ | 16,654 |
| $ | 3,105 |
|
Total Exploration Expense |
| $ | 150,701 |
| $ | 152,096 |
| $ | 84,868 |
|
Impairment of Operating Assets
Developed crude oil and natural gas properties and other long-lived assets are assessed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. The Company performs this review of recoverability by estimating future cash flows. If the sum of the expected future cash flows is less than the carrying amount of the asset, an impairment is recognized based on the fair value of the assets as determined using the expected present value of future net cash flows. The Company recorded no operating asset impairments during 2002, 2001 or 2000. Individually significant unproved crude oil and natural gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance.
Selling, General and Administrative Expenses (“SG&A”)
SG&A expenses increased $3.5 million in 2002 compared to 2001 and decreased $3.1 million in 2001 compared to 2000. The increase in SG&A expenses for 2002 is due to increased salary and legal expense, as well as increased costs associated with the Company’s international expansion. The decrease in 2001 compared to 2000 reflects the Company’s effort to reduce SG&A through efficiencies and other reduction measures.
8
Gathering, Marketing and Processing
NEMI markets the majority of the Company’s domestic natural gas, as well as certain third-party natural gas. NEMI sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. NEMI markets a portion of the Company’s domestic crude oil, as well as certain third-party crude oil. The Company records all of NEMI’s sales and expenses as gathering, marketing and processing revenues and expenses. All intercompany sales and expenses have been eliminated in the Company’s consolidated financial statements.
The gathering, marketing and processing revenues less expenses for NEMI are reflected in the table below.
(in thousands) |
| 2002 |
| 2001 |
| 2000 |
| ||||||||||||
| Crude |
| Natural |
| Crude |
| Natural |
| Crude |
| Natural |
| |||||||
Revenues |
| $ | 88,377 |
| $ | 625,714 |
| $ | 75,550 |
| $ | 645,400 |
| $ | 91,204 |
| $ | 498,729 |
|
Less: Cost of goods sold |
| 61,553 |
| 588,022 |
| 49,191 |
| 607,170 |
| 63,005 |
| 464,600 |
| ||||||
Net Revenues |
| 26,824 |
| 37,692 |
| 26,359 |
| 38,230 |
| 28,199 |
| 34,129 |
| ||||||
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Transportation |
| 20,323 |
| 28,284 |
| 19,739 |
| 27,779 |
| 19,455 |
| 24,014 |
| ||||||
General and administrative |
| 802 |
| 3,857 |
| 199 |
| 3,176 |
| 190 |
| 3,002 |
| ||||||
Total Expenses |
| $ | 21,125 |
| $ | 32,141 |
| $ | 19,938 |
| $ | 30,955 |
| $ | 19,645 |
| $ | 27,016 |
|
Gross Margin |
| $ | 5,699 |
| $ | 5,551 |
| $ | 6,421 |
| $ | 7,275 |
| $ | 8,554 |
| $ | 7,113 |
|
The margins for natural gas on a per MMBTU basis were $.035 for 2002 and 2001 and $.027 for 2000. The increase in natural gas margin on a per MMBTU basis for 2001 compared to 2000 was due to the improvement in natural gas prices. The margins for crude oil on a per Bbl basis were $.84 for 2002, $.95 for 2001 and $1.28 for 2000. The decrease in crude oil margin for 2002 compared to 2001 was due to increased general and administrative expenses coupled with higher transportation expense. The decrease in crude oil margin for 2001 compared to 2000 was due to lower crude oil prices.
Income Taxes
Income tax expense decreased to $21 million in 2002 from $66 million in 2001, primarily from the decrease in income. However, the effective income tax rate increased to 66 percent in 2002 from 43 percent in 2001. During 2002, more of the Company’s income was from international operations. Some of the countries in which the international operations were conducted have a higher statutory income tax rate than the United States. To a lesser extent, also impacting the effective rate in 2002 was the lower income level.
Discontinued Operations
The Company’s income from discontinued operations before taxes for 2002 was $10.4 million, a decrease of $60.7 million from 2001. The decrease was due primarily to a $56.4 million decrease in natural gas sales and a $6.1 million decrease in crude oil sales. The decrease in natural gas sales was the result of a 33 percent decline in natural gas production and a 29 percent decline in average natural gas price. The decrease in crude oil sales was the result of a 14 percent decline in crude oil production and a three percent decline in average crude oil price. Crude oil and natural gas operations expense and DD&A expense remained flat in 2002 compared to 2001.
Income from discontinued operations before taxes for 2001 was $71.1 million, a decrease of $12.7 million from 2000. The decrease was due primarily to an $11.1 million decrease in crude oil sales, resulting from a 17 percent decline in average crude oil price and a seven percent decrease in crude oil production. Natural gas sales remained flat in 2001 compared to 2000, with a five percent decrease in production being offset by a nine percent increase in average natural gas price. Expenses increased six percent due to a ten percent increase in DD&A expense.
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The effective income tax rate on income from discontinued operations was 35 percent for 2002, 2001 and 2000.
SUBSEQUENT EVENTS
ACCOUNTING FOR COSTS ASSOCIATED WITH MINERAL RIGHTS: During 2003 a reporting issue arose regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, excluding amortization, the Company would be required to reclassify certain amounts out of oil and gas properties and into a separate intangible assets line item. The Company has not yet determined fully the impact of this change; however, it is expected to significantly impact the Company’s balance sheet. The Company’s cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, the Company does not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on compliance with covenants under the Company’s debt agreements.
2003 PROPERTY SALES: During 2003, the Company identified five property packages for disposition. Bids have now been received on all five packages. Year-to-date, property sales have closed on four of the five packages, with the remaining property package expected to close during the first quarter of 2004. Total pretax proceeds on all five packages, before closing adjustments, are expected to be in excess of $110 million.
During the third quarter 2003, closed property sales resulted in a pretax gain of $9.9 million. Also during the third quarter 2003, certain properties in two packages were classified as held for sale, written down by $18.3 million to fair value, pretax, and reported in discontinued operations.
Subsequent to September 30, 2003, the remaining asset package met the criteria to be classified as held for sale. During the fourth quarter 2003, Noble Energy has closed sales on properties located in California, Oklahoma and Wyoming. A package of Gulf of Mexico properties is expected to close during the first quarter 2004. The transfer of the remaining property package to discontinued operations and the timing of completed sales will result in an expected non-cash, pretax write-down to fair value and realized loss of approximately $40 million ($26 million after tax) (unaudited). The total non-cash charge will appear in discontinued operations for the fourth quarter 2003.
CREDIT FACILITY: The Company entered into a new 364-day credit facility in the amount of $300 million effective November 3, 2003 that replaced the $200 million credit facility that would have expired November 26, 2003. The interest rate on the new credit facility is LIBOR plus a range of 62.5 to 150 basis points, depending upon the percentage of utilization.
ADOPTION OF SFAS NO. 150: During the second quarter of 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” As a result, the Company recorded an additional 1.04 million shares of treasury stock at a cost of $36.6 million and an obligation of $36.6 million. During 2003 the Company paid the obligation of $36.6 million in full.
DIVIDEND PAYMENT: On October 28, 2003, the Company’s Board of Directors declared a quarterly cash dividend of five cents per common share payable November 24, 2003 to the shareholders of record on November 10, 2003. This payment represents an increase of one cent per share, or 25 percent, over the Company’s previous quarterly payment of four cents per share.
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LEGAL UPDATE: On January 13, 2003, the Noble Defendants each filed an answer to ENA’s complaint. On January 29, 2003, the Noble Defendants filed the Motion of Noble Energy Marketing, Inc., as Successor to Noble Gas Marketing, Inc., Aspect Resources L.L.C., and Noble Energy, Inc., as Successor to Samedan Oil Corporation, to Compel Arbitration. On March 4, 2003, the Court issued its Order Governing Mediation of Trading Cases and Appointing the Honorable Allan L. Gropper as Mediator (the “Mediation Order”) which, among other things, abated this case and referred it to mediation along with other pending adversary proceedings in the Enron bankruptcy cases which involve disputes arising from or in connection with commodity trading contracts. Pursuant to the Mediation Order, the Honorable Allan L. Gropper (United States Bankruptcy Judge for the Southern District of New York) is acting as mediator for this case and the other trading cases which have been referred to him. The mediation for this case was held on December 17, 2003 and no resolution was reached.
Future Trends
The Company expects crude oil and natural gas production to increase in 2003 and 2004 compared to 2002. The increased production in 2003 is expected primarily from the phase 2A expansion of the Alba field in Equatorial Guinea, the startup of production from the Mari-B field, offshore Israel, production from the CDX block in China and a full year of production in Ecuador. The increase in 2004 is expected primarily from the continued expansion of markets in Israel and the phase 2B expansion of the LPG plant in Equatorial Guinea.
The Company recently set its 2003 capital expenditures budget at approximately $510 million. Such expenditures are planned to be funded principally through internally generated cash flows. The Company believes that it has the capital structure to take advantage of strategic acquisitions, as they become available, through internally generated cash flows or available lines of credit and other borrowing opportunities.
SFAS No. 148, “Accounting for Stock-Based Compensation,” was issued in December 2002. This statement amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide for alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation. It also amends the disclosure provisions of that statement to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation.
The Company currently accounts for stock-based employee compensation plans under the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” The Company has not determined if it will adopt the fair value provisions of SFAS No. 123.
In June 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on certain issues contained in Topic 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts” under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” While the Company does not engage in energy trading activities, the EITF has expanded its definition of energy trading activities to include the marketing activities in which the Company is engaged. As of January 1, 2003, the Company presents its gathering, marketing and processing activities in the statement of operations for all periods on a net rather than a gross basis. The change will significantly decrease reported marketing sales and purchases, but will have no effect on operating income or cash flow.
Management believes that the Company is well positioned with its balanced reserves of crude oil and natural gas and downstream projects. The uncertainty of commodity prices continues to affect the crude oil, natural gas and methanol industries. The Company cannot predict the extent to which its revenues will be affected by inflation, government regulation or changing prices.
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Quantitative and Qualitative Disclosures About Market Risk.
The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, the Company, from time to time, has used derivative hedging instruments and may do so in the future as a means of managing its exposure to price changes.
During 2002, the Company entered into various natural gas costless collars, natural gas costless collar combinations and crude oil costless collar transactions related to its production. The table below depicts the various transactions for 2002.
Natural Gas |
| Crude Oil |
| ||||
Hedge MMBTUpd |
| 170,274 |
| Hedge Bpd |
| 5,247 |
|
Floor price range |
| $2.00 - $3.50 |
| Floor price range |
| $23.00 - $24.00 |
|
Ceiling price range |
| $2.45 - $5.10 |
| Ceiling price range |
| $29.30 - $30.10 |
|
Percent of daily production |
| 50 | % | Percent of daily production |
| 17 | % |
Gain (loss) per Mcf |
| $.04 |
| Gain (loss) per Bbl |
| $(.01 | ) |
As of December 31, 2002, the Company had entered into costless collars related to its natural gas and crude oil production to support the Company’s investment program as follows:
Natural Gas |
| Crude Oil |
| ||||||
Production |
| MMBTU |
| Price |
| Bbls |
| Price |
|
1Q 2003 |
| 185,000 |
| $3.87 - $4.82 |
| 15,000 |
| $23.00 - $28.63 |
|
2Q 2003 |
| 185,000 |
| $3.43 - $4.57 |
| 15,000 |
| $23.00 - $28.63 |
|
3Q 2003 |
| 185,000 |
| $3.43 - $4.60 |
| 10,000 |
| $23.00 - $27.95 |
|
4Q 2003 |
| 185,000 |
| $3.43 - $4.84 |
| 10,000 |
| $23.00 - $27.95 |
|
The contracts entitle the Company (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the last scheduled NYMEX trading day applicable for each calculation period is less than the floor price. The Company would pay the counterparty if the settlement price for the last scheduled NYMEX trading day applicable for each calculation period were more than the ceiling price. The amount payable by the floating price payor, if the floating price is above the ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the ceiling price in respect of each calculation period. The amount payable by the fixed price payor, if the floating price is below the floor price, is the product of the notional quantity per calculation period and the excess, if any, of the floor price over the floating price in respect of each calculation period.
During 2001, the Company had natural gas costless collars for the fourth quarter of 2001 for 50,000 MMBTU of natural gas per day, with a floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net effect of this fourth quarter 2001 hedge was a $.03 per Mcf increase in the average natural gas price for the year 2001. Of the 50,000 MMBTU per day of costless collars, 25,000 MMBTU per day were terminated early, at a gain. As a result, the Company recognized an additional $.70 per MMBTU on the 25,000 MMBTU of natural gas per day in 2001.
NEMI, from time to time, employs hedging arrangements in connection with its purchases and sales of production. While most of NEMI’s purchases are made for an index-based price, NEMI’s customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NEMI may convert a fixed or NYMEX sale to an index-based sales price (such as by purchasing an index-based futures contract obligating NEMI for delivery of production). Due to the size of such transactions and certain restraints imposed
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by contract and by Company guidelines, as of December 31, 2002, the Company had no material market risk exposure from NEMI’s hedging activity.
The Company has a $400 million credit agreement that exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. The interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis points depending upon the percentage of utilization and credit rating. At December 31, 2002, there was $380 million borrowed against this credit agreement with an interest rate of 2.47 percent and a maturity date of November 30, 2006. A ten percent change in the December 31, 2002 interest rate on this $380 million would result in a change in interest expense of $937,080. All other significant Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates. For more information, see “Financial Statements and Supplementary Data—Note 3 - Debt” of this Form 8-K.
The Company does not enter into foreign currency derivatives. The U.S. dollar is considered the primary currency for each of the Company’s international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Transaction gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other income on the statement of operations. However, certain sales transactions are concluded in foreign currencies and the Company, therefore, is exposed to potential risk of loss based on fluctuation in exchange rates from time to time.
Cautionary Statement for Purposes of the Private Securities Litigation Reform Act of 1995 and Other Federal Securities Laws
General. Noble Energy is including the following discussion to generally inform its existing and potential security holders of some of the risks and uncertainties that can affect the Company and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, the Company’s management or persons acting on management’s behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include, but are not limited to, projections and estimates concerning the timing and success of specific projects and the Company’s future: (1) income, (2) crude oil and natural gas production, (3) crude oil and natural gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes the Company will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 8-K, the matters discussed in this Form 8-K are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.
Noble Energy believes the factors discussed below are important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made herein or elsewhere by the Company or on its behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. Noble Energy does not intend to update its description of important factors each time a potential important factor arises. The Company advises its stockholders that they should: (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements, and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere. All of such forward-looking statements are qualified in their entirety by this cautionary statement.
Volatility and Level of Hydrocarbon Commodity Prices. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market supply and demand fundamentals and changes in the political, regulatory and economic climates and other factors that affect commodities markets generally and are outside of Noble Energy’s control. Some of Noble Energy’s projections and estimates are based on assumptions as to the future prices of
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natural gas and crude oil. These price assumptions are used for planning purposes. The Company expects its assumptions may change over time and that actual prices in the future may differ from our estimates. Any substantial or extended change in the actual prices of natural gas and/or crude oil could have a material effect on: (1) the Company’s financial position and results of operations, (2) the quantities of natural gas and crude oil reserves that the Company can economically produce, (3) the quantity of estimated proved reserves that may be attributed to its properties, and (4) the Company’s ability to fund its capital program.
Production Rates and Reserve Replacement. Projecting future rates of crude oil and natural gas production is inherently imprecise. Producing crude oil and natural gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering issues, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climates. Another factor affecting production rates is Noble Energy’s ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, the Company’s ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, Noble Energy’s finding and development costs may not justify the use of resources to explore for and develop such reserves.
Reserve Estimates. Noble Energy’s forward-looking statements are predicated, in part, on the Company’s estimates of its crude oil and natural gas reserves. All of the reserve data in this Form 8-K or otherwise made by or on behalf of the Company are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved natural gas and crude oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond the Company’s control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, estimates made by different engineers may vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
Laws and Regulations. Noble Energy’s forward-looking statements are generally based on the assumption that the legal and regulatory environments will remain stable. Changes in the legal and/or regulatory environments could have a material effect on the Company’s future results of operations and financial condition. Noble Energy’s ability to economically produce and sell crude oil, natural gas, methanol and power is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting: (1) crude oil and natural gas production, (2) taxes applicable to the Company and/or its production, (3) the amount of crude oil and natural gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities, and (5) the marketing of competitive fuels. The Company’s operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Noble Energy’s forward-looking statements are generally based upon the expectation that the Company will not be required, in the near future, to expend cash to comply with environmental laws and regulations that are material in relation to its total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to accurately predict the ultimate financial impact of compliance.
Drilling and Operating Risks. Noble Energy’s drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of crude oil, natural gas or well fluids. In addition, a substantial amount of the Company’s operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision, and damage or loss from severe weather. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.
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Competition. The Company’s forward-looking statements are generally based on a stable competitive environment. Competition in the industry is intense. Noble Energy actively competes for reserve acquisitions and exploration leases and licenses, for the labor and equipment required to operate and develop crude oil and natural gas properties and in the gathering and marketing of natural gas, crude oil, methanol and power. The Company’s competitors include the major integrated oil companies, independent crude oil and natural gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers, many of whom have greater financial resources than the Company.
Noble Energy believes that the location of its properties, its expertise in exploration, drilling and production operations, the experience of its management and the efforts and expertise of its marketing units generally enable it to compete effectively. In making projections with respect to numerous aspects of the Company’s business, Noble Energy generally assumes that there will be no material adverse change in competitive conditions.
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