EXHIBIT 99.4
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Statements in the following discussion may be forward-looking and involve risks and uncertainties. The Company’s financial results are most directly affected by changing prices for its production. Changing prices can influence not only current results of operations but the determination of the Company’s proved reserves and available sources of financing, including the determination of the borrowing base under its bank credit facility. The Company’s results depend not only on hydrocarbon prices generally, but on its ability to market its production on favorable terms. On a longer term basis, the Company’s financial condition and results of operations are affected by its ability to replace reserves as they are produced through successful exploration, development and acquisition activities. The Company’s results could also be adversely affected by adverse regulatory developments and operational risks associated with oil and gas operations. Some of the other risks and uncertainties that may affect the Company’s results are mentioned in the discussion that follows.
The following discussion of the Company’s financial condition and results of operations reflects the recasting as discontinued operations of the Company’s Thailand and Hungary operations. See “Executive Summary — Thailand and Hungary Disposition”. Except where noted, the following discussion relates to the Company’s continuing activities only.
Executive Overview
The Company’s objective is to cost effectively explore for, develop, acquire and produce oil and gas in select locations worldwide. In pursuit of that objective, the Company’s goal for each year is to add more oil and gas reserves than it produces. 2004 marked the thirteenth consecutive year of reserve replacement for the Company.
The Company pursues a balanced approach in core areas located in major oil and gas provinces in the United States and internationally. The Company follows a strict set of criteria when selecting areas of the world in which to explore. Areas selected are viewed as having proven oil and gas resources, having reasonable economic terms and possessing low political risk. Following these criteria, the Company, during 2004, operated internationally in several selected areas: Gulf of Thailand, Hungary and offshore New Zealand. See “Thailand and Hungary Disposition” below for information relating to the subsequent disposition of the Company’s operations In Thailand and Hungary. The Company also seeks to maintain a balanced mixture of the gas/oil ratio of its proven reserves base.
At the end of 2004, proven reserves from continuing operations were 1,437 Bcfe and production for the year from continuing operations averaged more than 74,000 BOE per day (446,000 Mcfe per day). Oil and gas pricing and production volumes are important components of an exploration and development company’s growth in net income and cash flow. In 2004, oil and gas pricing for the Company was strong, with the average price increasing 21% over 2003 on an equivalent barrel basis.
The Company continues to have a strong balance sheet and to improve its financial leverage, although long-term debt increased, primarily as a result of acquisitions, to $755 million at December 31, 2004 from $487 million at year-end 2003. Interest charges were reduced from $46.3 million in 2003 to $29.3 million in 2004. The Company’s debt to capitalization ratio, an indicator of a company’s financial strength, was 30%. Cash and cash equivalents increased from $179 million to $221 million at year-end 2004. Company management believes being fiscally conservative is essential to position the Company for future growth.
Oil and gas capital and exploration expenditures for 2004 were approximately $931 million. Exploration & development operations were allocated approximately $322 million, and approximately $609 million was spent on selective acquisitions in the Company’s core areas of operations. During 2004, approximately 269 Bcfe of proven reserves were added to the Company’s reserves ledger.
Hurricane Ivan Update
Company operated Gulf of Mexico platforms did not sustain major damage as a result of Hurricane Ivan. However, damages to outside owned and operated platforms and pipelines are continuing to cause a portion of the Company’s Gulf of Mexico production to remain shut-in. As of February 22, 2005, some 4,500 barrels of oil per day and 27 million cubic feet of natural gas per day from Main Pass, South Pass and Viosca Knoll areas remain shut-in, and repairs to the infrastructure were underway, with the expectation that approximately 70% of the production from these fields would be restored by the end of March, 2005. In order to protect its cash flow, the Company has business interruption insurance for certain of the blocks affected by the shut-in; the Company expects to receive payment from its business interruption insurance policy until production is fully restored for a period of up to one year. The daily indemnity amount expected to be paid to the Company is
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approximately $600,000 per day for the Main Pass 61/62 Blocks and approximately $50,000 per day for other blocks affected by the shut-in. These amounts will be reduced by cash flow from partially restored production.
Thailand and Hungary Disposition
The Company announced during the first quarter of 2005 that it would consider the sale or swap of the Company’s operations in Thailand and Hungary.
On June 7, 2005, the Company completed the sale of its wholly owned subsidiary Pogo Hungary, Ltd. (“Pogo Hungary”) for a purchase price of $9 million.
On June 17, 2005, the Company announced the sale to PTTEP Offshore Investment Company Limited and Mitsui Oil Exploration Co., Ltd. of its operations in Thailand, conducted through its wholly owned subsidiary Thaipo Ltd. and its 46.34% interest in B8/32 Partners Ltd. (collectively the “Thailand Entities”) for a purchase price of $820 million. The preferential purchase rights held by the other owners of the Thailand concession expired without exercise on July 19, 2005. The Company completed the sale of the Thailand Entities on August 17, 2005.
Share Repurchase
During the first quarter of 2005, the Company announced a share repurchase plan. The Company expects to expend not less than $275 million nor more than $375 million to effect the repurchases. Based on stock prices current prior to March 7, 2005, the repurchase would represent approximately 9% to 12% of the shares outstanding at December 31, 2004.
2005 Capital Budget
The Company has established a $345 million exploration and development budget (excluding property acquisitions). The Company expects to spend approximately $187 million on exploration and $158 million on development activities. The capital budget calls for the drilling of approximately 226 wells during 2005.
Results of Operations
Oil and Gas Revenues
The Company’s oil and gas revenues for 2004 were $973,083,000, an increase of approximately 14% from oil and gas revenues of $856,074,000 for 2003, which were an increase of approximately 59% from oil and gas revenues of $537,717,000 for 2002. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between years:
| | 2004 | | 2003 | |
| | Compared to | | Compared to | |
| | 2003 | | 2002 | |
| | | | | |
Increase (decrease) in oil and gas revenues resulting from variances in: | | | | | |
Natural gas - | | | | | |
Price | | $ | 43,010 | | $ | 148,782 | |
Production | | 72,285 | | 17,220 | |
| | 115,295 | | 166,002 | |
Crude oil and condensate - | | | | | |
Price | | 139,431 | | 46,718 | |
Production | | (148,733 | ) | 97,687 | |
| | (9,302 | ) | 144,405 | |
| | | | | |
Natural gas liquids (“NGL”) | | 11,016 | | 7,950 | |
Increase in oil and gas revenues | | $ | 117,009 | | $ | 318,357 | |
The increase in the Company’s oil and gas revenues in 2004, compared to 2003, is related to increases in both the average price that the Company received for its hydrocarbon production volumes and an increase in the Company’s natural gas production volumes, partially offset by a decrease in crude oil and condensate production volumes. The increase in the Company’s oil and gas revenues in 2003, compared to 2002, is related to increases in both the average price that the Company received for its hydrocarbon production volumes and an increase in the Company’s natural gas and crude oil and condensate
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production volumes. The increase in oil and gas revenues for 2004, compared to 2003 and 2002, was also the result of an increase in the average price that the Company received for its NGL production volumes from $14.94 and $21.59 in 2002 and 2003, respectively, to $28.09 in 2004.
| | | | | | % Change | | | | % Change | |
| | | | | | 2004 | | | | 2003 | |
| | | | | | to | | | | to | |
Comparison of Increases (Decreases) in: | | 2004 | | 2003 | | 2003 | | 2002 | | 2002 | |
Natural Gas — | | | | | | | | | | | |
Average prices (a) | | $ | 5.73 | | $ | 5.17 | | 11 | % | $ | 3.15 | | 64 | % |
Average daily production volumes
(MMcf per day): | | 244.3 | | 210.4 | | 16 | % | 201.3 | | 5 | % |
| | | | | | | | | | | |
Crude Oil and Condensate — | | | | | | | | | | | |
Average prices (b) | | $ | 38.59 | | $ | 29.08 | | 33 | % | $ | 24.95 | | 17 | % |
Average daily production volumes
(Bbls per day): | | 29,530 | | 40,173 | | (26 | )% | 30,971 | | 30 | % |
| | | | | | | | | | | |
Total Liquid Hydrocarbons — | | | | | | | | | | | |
Average daily production volumes
(Bbls per day) | | 33,750 | | 44,282 | | (24 | )% | 35,451 | | 25 | % |
(a) Average prices reflect the impact of the Company’s price hedging activity. The Company had no price hedging activity related to 2004 production. Price hedging activity reduced the average price $0.17 during 2003 and added $0.04 to the average price of the Company’s natural gas production during 2002.
(b) Average prices include the impact of the Company’s price hedging activity. The Company had no price hedging activity related to 2004 production. Price hedging activity reduced the average price of the Company’s crude oil and condensate production $0.69 during 2003 and added $0.08 to the average price during 2002. For average prices, sales volumes equate to actual production.
Natural Gas Production. The increase in the Company’s natural gas production during 2004, compared to 2003, was primarily related to acquisitions made during 2004 and late 2003 and, to a lesser extent, increased production from the continuing success of the Company’s exploration program at its Los Mogotes Field in South Texas. These production gains were partially offset by shut-in production resulting from the infrastructure damage caused by Hurricane Ivan in the final months of 2004 and natural production declines at other properties. The increase in the Company’s natural gas production during 2003, compared to 2002, was primarily related to increased production from the continuing success of the Company’s exploration program at its Los Mogotes Field in South Texas and, to a lesser extent, an increase in the production capacity of the Lost Cabin Gas Plant located on the Company’s Madden Field in Wyoming. These production gains were partially offset by natural production declines at other properties.
Crude Oil and Condensate Production. The decrease in the Company’s crude oil and condensate production during 2004, compared to 2003, resulted primarily from shut-in production related to the infrastructure damage caused by Hurricane Ivan in the final quarter of 2004 and natural production declines at the Company’s Main Pass Blocks 61/62 Field in the Gulf of Mexico. The increase in the Company’s crude oil and condensate production during 2003, compared to 2002, resulted primarily from the success of development programs at the Company’s Main Pass Blocks 61/62 Field in the Gulf of Mexico, partially offset by natural production declines at certain other properties.
NGL Production. The Company’s oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for 2004, compared with 2003, related to an increase in the average price that the Company received for its NGL production to $28.09 in 2004 from $21.59 in 2003, in addition to a slight increase in NGL production volumes. The increase in NGL revenues for 2003, compared with 2002, related to an increase in the average price that the Company received for its NGL production to $21.59 in 2003 from $14.94 in 2002, partially offset by a slight decline in NGL production volumes.
Other Revenues
Other revenue is revenue derived from sources other than the current production of hydrocarbons. This revenue includes, among other items, insurance proceeds (excluding those related to operating expenses, which are credited against the appropriate expense category), pipeline imbalance settlements and revenue from salt water disposal activities. The increase in the Company’s other revenues in 2004, compared to either 2003 or 2002, is related primarily to $11.1 million of business interruption insurance recorded in 2004 with no comparable insurance claims in either 2003 or 2002. The business interruption insurance claim relates to the shut-in of a significant portion of the Company’s Gulf of Mexico production during the fourth
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quarter of 2004 as a result of the infrastructure damage caused by Hurricane Ivan. Repairs to the infrastructure were underway in March 2005, with the expectation that approximately 70% of the production from the affected fields would be restored by the end of March, 2005.
Costs and Expenses
| | | | | | % Change | | | | % Change | |
Comparison of Increases (Decreases) in: | | 2004 | | 2003 | | 2004 to 2003 | | 2002 | | 2003 to 2002 | |
| | | | | | | | | | | |
Lease Operating Expenses | | $ | 100,506,000 | | $ | 81,731,000 | | 23 | % | $ | 74,416,000 | | 10 | % |
General and Administrative Expenses | | $ | 62,506,000 | | $ | 54,068,000 | | 16 | % | $ | 43,513,000 | | 24 | % |
Exploration Expenses | | $ | 21,739,000 | | $ | 6,899,000 | | 215 | % | $ | 4,161,000 | | 66 | % |
Dry Hole and Impairment Expenses | | $ | 61,634,000 | | $ | 30,673,000 | | 101 | % | $ | 26,999,000 | | 14 | % |
Depreciation, Depletion and | | | | | | | | | | | |
Amortization (DD&A) Expenses | | $ | 251,876,000 | | $ | 229,881,000 | | 10 | % | $ | 210,649,000 | | 9 | % |
DD&A rate | | $ | 1.54 | | $ | 1.32 | | 17 | % | $ | 1.39 | | (5 | )% |
Mcfe produced | | 163,527,914 | | 173,779,594 | | (6 | )% | 151,105,909 | | 15 | % |
Production and Other Taxes | | $ | 44,104,000 | | $ | 23,735,000 | | 86 | % | $ | 20,058,000 | | 18 | % |
Transportation and Other | | $ | 19,488,000 | | $ | 23,892,000 | | (18 | )% | $ | 12,879,000 | | 86 | % |
Interest— | | | | | | | | | | | |
Charges | | $ | (29,333,000 | ) | $ | (46,360,000 | ) | (37 | )% | $ | (57,450,000 | ) | (19 | )% |
Capitalized Interest Expense | | $ | 14,216,000 | | $ | 16,531,000 | | (14 | )% | $ | 24,033,000 | | (31 | )% |
Loss on debt extinguishment | | $ | (13,759,000 | ) | $ | (5,893,000 | ) | 133 | % | $ | — | | N/M | |
Minority Interest - Dividends and Costs | | $ | — | | $ | — | | N/M | | $ | (4,140,000 | ) | N/M | |
Income Tax Expense | | $ | (148,866,000 | ) | $ | (137,371,000 | ) | 8 | % | $ | (43,538,000 | ) | 216 | % |
Lease Operating Expenses
The increase in lease operating expenses for 2004, compared to 2003, is due primarily to increased expenses incurred on the properties acquired by the Company during 2004 and the latter part of 2003, increased maintenance expenses on several of the Company’s significant offshore properties related to the effects of Hurricane Ivan and also to increased expenses incurred as the Company continues to expand production in the Los Mogotes field in South Texas. The increase in lease operating expenses for 2003, compared to 2002, was due to higher production from the Company’s onshore properties and additional Gulf of Mexico platforms added during 2002 and the resulting increase in operating expenses as additional wells were subsequently brought on production and, to a lesser extent, increased expenses at the Lost Cabin gas plant in the Madden Unit, which was expanded in late 2002.
On a per unit of production basis, the Company’s total lease operating expenses were $0.49 per Mcfe for 2002, $0.47 per Mcfe for 2003 and $0.61 per Mcfe for 2004. The increased unit costs in 2004 were primarily related to the increased expense associated with Hurricane Ivan remediation efforts and the decreased production volumes discussed above.
General and Administrative Expenses
The increase in general and administrative expenses for 2004, compared with 2003, is primarily related to increases in compensation and related benefit expense and to increased professional fees (due in part to compliance with Sarbanes-Oxley legislation). The increase in general and administrative expenses for 2003, compared with 2002, primarily related to higher benefit expenses, increases in professional fees, increased insurance costs and expenses related to the Company’s decision, effective January 1, 2003, to expense stock-based compensation. On a per unit of production basis, the Company’s general and administrative expenses were $0.38 per Mcfe in 2004, $0.31per Mcfe in 2003 and $0.29 per Mcfe in 2002.
Exploration Expenses
Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties (“delay rentals”) and exploratory geological and geophysical costs that are expensed as incurred. The increase in exploration expenses for 2004, compared to 2003, resulted primarily from increased 3-D seismic acquisition activities in the Gulf of Mexico and seismic operations in the Company’s Gulf Coast division. The increase in exploration expenses for 2003, compared to 2002, resulted primarily from increased 3-D seismic acquisition activities in the Gulf of Mexico and seismic operations in the Company’s Western region.
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Dry Hole and Impairment Expenses
Dry hole and impairment expenses relate to costs of unsuccessful exploratory wells drilled and impairment of oil and gas properties. During 2004 the Company drilled 7 gross unsuccessful exploratory wells (5.6 net to the Company’s interest), in 2003 the Company drilled 5 unsuccessful exploratory wells (4.0 net to the Company’s interest) and in 2002 the Company drilled 6 unsuccessful exploratory wells (5.2 net to the Company’s interest). The Company had exploratory and development drilling success rates of 94% in 2004, 93% in 2003 and 90% in 2002. The Company had approximately $11,806,000 of costs related to exploratory wells in progress or temporarily abandoned pending evaluation (located primarily in the Gulf of Mexico) at December 31, 2004 that had not been evaluated as of March 1, 2005.
Generally accepted accounting principles require that if the expected future cash flow of the Company’s reserves on a property fall below the cost that is recorded on the Company’s books, these costs must be impaired and written down to the property’s fair value. Depending on market conditions, including the prices for oil and natural gas, and the results of operations, a similar test may be conducted at any time to determine whether impairments are appropriate. Depending on the results of this test, an impairment could be required on some of the Company’s proved properties and this impairment could have a material negative non-cash impact on the Company’s earnings and balance sheet. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. As a result of these reviews, the Company recognized impairments to oil and gas properties of approximately $21,372,000 during 2004, approximately $10,542,000 during 2003 and $6,191,000 during 2002.
Depreciation, Depletion and Amortization Expenses
The Company’s provision for DD&A expense is based on its capitalized costs and is determined on a cost center by cost center basis using the units of production method. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities.
The increase in the Company’s DD&A expense for 2004, compared to 2003, resulted primarily from a decrease in the percentage of the Company’s production coming from fields that have DD&A rates that are lower than the Company’s recent historical composite DD&A rate (principally properties in the Gulf of Mexico which were shut-in due to hurricane downtime) and a corresponding increase in the percentage of the Company’s production coming from fields that have DD&A rates that are higher than the Company’s recent historical composite rate (principally increased production from onshore properties acquired by acquisition).
The increase in the Company’s DD&A expense for 2003, compared to 2002, resulted primarily from an increase in the Company’s natural gas and liquid hydrocarbon production, partially offset by a decrease in the Company’s composite DD&A rate. The decrease in the composite DD&A rate for all of the Company’s producing fields for 2003, compared to 2002, resulted primarily from an increased percentage of the Company’s production coming from fields that have DD&A rates lower than the Company’s recent historical composite rate (principally certain Gulf of Mexico properties) and a corresponding decrease in the percentage of the Company’s production coming from fields that have DD&A rates higher than the Company’s recent historical composite DD&A rate.
Production and Other Taxes
The increase in production and other taxes for 2004, compared to 2003, and for 2003, compared to 2002, is primarily related to increased severance taxes due to higher prices and higher onshore production volumes.
Transportation and Other
Transportation and other expense includes the Company’s cost to move its products to market (transportation costs), accretion expense related to Company asset retirement obligations under an accounting pronouncement adopted on January 1, 2003, natural gas purchase costs, tubular inventory valuation write-offs and allowances, and various other operating expenses, none of which represents more than 5% of this expense category. The decrease in other expense for 2004, compared to 2003, relates primarily to the inclusion in 2003 of approximately $5.6 million more of valuation allowances and reserves on items discussed above, than were expensed in 2004. The increase in other expense for 2003, compared to 2002, relates primarily to the inclusion of $3,989,000 of expense related to the accretion of the Company’s asset retirement obligation and a $1,450,000 write down of the cost of the Company’s tubular inventory stock, for which no comparable expenses were incurred in 2002. The Company incurred transportation expense of $13,318,000 in 2004, $12,980,000 in 2003 and $10,140,000 in 2002.
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Interest
Interest Charges. The decrease in the Company’s interest charges for 2004, compared to 2003, resulted primarily from a decrease in the average amount of the Company’s outstanding debt during the first eleven months of the year and the repayment of higher cost debt during the year, resulting in a lower weighted average cost of debt. The Company did incur $317 million in additional debt during December 2004 primarily related to acquisitions, but this did not have a significant impact on the Company’s 2004 interest expense. The decrease in the Company’s interest charges for 2003, compared to 2002, resulted primarily from a decrease of approximately $236 million in the Company’s outstanding debt during the year, partially offset by an increase in the average interest rate on the debt that remained outstanding.
Capitalized Interest
Interest costs related to financing major oil and gas projects in progress are required to be capitalized until the projects are substantially complete and ready for their intended use if projects are evaluated as successful. The decrease in capitalized interest for 2004, compared to 2003, resulted from a decrease in the weighted average rate on borrowings incurred by the Company (discussed above under “Results of Operations—Interest Charges”) and applied to such capital expenditures to arrive at the total amount of capitalized interest, partially offset by an increase in the amount of capital expenditures subject to interest capitalization during 2004 (approximately $210,000,000) compared to 2003 (approximately $192,000,000). The decrease in capitalized interest for 2003, compared to 2002, resulted primarily from a decrease in the amount of capital expenditures subject to interest capitalization during 2003 (approximately $192,000,000) compared to 2002 (approximately $346,000,000). This decrease was also impacted by changes in the weighted average rate on borrowings incurred by the Company and applied to such capital expenditures to arrive at the total amount of capitalized interest.
Loss on Debt Extinguishment
The loss on debt extinguishment for 2004 is related to redemption premiums paid and/or unamortized debt issuance costs which were expensed due to the redemption of the 2009 Notes and the replacement of the Company’s previous bank credit facility with a new credit facility. The loss on debt extinguishment for 2003 is related to redemption premiums paid and unamortized debt issuance costs which were expensed due to the redemption of the 2006 Notes and 2007 Notes. No comparable costs were incurred in 2002.
Minority Interest—Dividends and Costs Associated with Mandatorily Redeemable Convertible Preferred Securities of a Subsidiary Trust
Pogo Trust I, a business trust in which the Company owned all of the issued common securities, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. Pogo Trust I called the Trust Preferred Securities for redemption on June 3, 2002. Prior to their redemption, holders of 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities converted their Trust Preferred Securities, representing over $149,850,000 face value of Trust Preferred Securities, into 6,309,972 shares of the Company’s common stock. In connection with the redemption, Pogo Trust I paid a total of $147,000 to former holders of the Trust Preferred Securities. Subsequent to June 3, 2002, there were no Trust Preferred Securities outstanding. The amounts recorded under Minority Interest — Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities.
Income Tax Expense
Changes in the Company’s income tax expense are a function of the Company’s consolidated effective tax rate and its pre-tax income and the jurisdiction in which the income is earned. The increase in the Company’s tax expense for 2004, compared to 2003, and for 2003, compared to 2002, resulted primarily from increases in pre-tax income in the later years. The Company’s consolidated effective tax rate for 2004, 2003 and 2002 was 37.4%, 36.9% and 38.8%, respectively.
Discontinued Operations
The Thailand Entities and Pogo Hungary are classified as discontinued operations in the Company’s financial statements. The summarized financial results and financial position data of the discontinued operations were as follows (amounts expressed in thousands):
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Operating Results Data
| | Year Ended December 31, | |
| | 2004 | | 2003 | | 2002 | |
Revenues | | $ | 335,291 | | $ | 303,491 | | $ | 212,778 | |
Costs and expenses | | (237,097 | ) | (163,388 | ) | (122,006 | ) |
Other income | | 308 | | 2,520 | | 1,854 | |
Income before income taxes | | 98,502 | | 142,623 | | 92,626 | |
Income taxes | | (85,783 | ) | (82,751 | ) | (54,242 | ) |
Income from discontinued operations, net of tax | | $ | 12,719 | | $ | 59,872 | | $ | 38,384 | |
| | | | | | | | | | | |
The decrease in income from discontinued operations for 2004, compared to 2003, primarily relates to dry hole and impairment costs incurred in Hungary and to increased Special Remunitory Benefit (SRB) costs incurred in the Kingdom of Thailand, which were only partially offset by increased revenues in the Kingdom of Thailand. The Company recognized no tax benefit for its costs in Hungary, resulting in a high effective tax rate for each of the periods presented. The increase in income from discontinued operations for 2003, compared to 2002, resulted primarily from increased oil and gas revenues in the Kingdom of Thailand, partially offset by increased SRB costs and lease operating expenses on the Company’s concession in the Kingdom.
Cumulative Effect of Change in Accounting Principle
The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”), as of January 1, 2003. SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, the Company recorded an after-tax charge to recognize the cumulative effect of a change in accounting principle of $4,166,000. This charge was required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, and also to increase the carrying amount of the associated long-lived asset and its accumulated depreciation.
Liquidity and Capital Resources
The Company’s primary needs for cash are for exploration, development, acquisition and production of oil and gas properties, repayment of principal and interest on outstanding debt and payment of income taxes. The Company funds its exploration and development activities primarily through internally generated cash flows and budgets capital expenditures based on projected cash flows. The Company adjusts capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition results, and cash flow. The Company has historically utilized net cash provided by operating activities, available cash, debt, and equity as capital resources to obtain necessary funding for all other cash needs.
The Company’s cash flow provided by operating activities for 2004 was $738,715,000. This compares to cash flow from operating activities of $744,559,000 in 2003 and $466,479,000 in 2002. The resulting changes are attributable to the reasons described under “Results of Operations” above. Cash flow from operating activities in 2004 was sufficient to fund 82% of the $901,006,000 in cash expenditures for capital and exploration projects and acquisitions for the year. To fund the remaining expenditures, the Company borrowed approximately $208,218,000 of cash (net of repayments and the redemption discussed below). The Company paid $13,607,000 of dividends on its common stock during 2004. As of December 31, 2004, the Company had cash and current investments of $221,456,000 (including $195,669,000 in international subsidiaries which the Company intends to reinvest in its foreign operations subject to its evaluation of the new tax provisions discussed in “American Jobs Creation Act of 2004” below) and long-term debt obligations of $755,000,000 with no principal repayment obligations until 2009. On April 19, 2004, the Company paid $157,782,000 (excluding accrued interest) in cash to holders of its 103/8% Senior Subordinated Notes due 2009 (the “2009 Notes”). The redemption was made at 105.188% of the face amount of the 2009 Notes. The cash redemption payment was funded through borrowings under the Company’s existing bank credit facility. The Company may elect to repurchase additional debt through market transactions, privately negotiated transactions or otherwise, depending on market conditions, liquidity requirements, contractual restrictions and other factors.
On December 16, 2004 the Company entered into a new Credit Agreement, replacing its then existing credit agreement dated as of March 8, 2001, as amended. The new Credit Agreement is with various financial institutions and provides for revolving credit borrowings up to a maximum principal amount of $750 million outstanding at any one time, with borrowings not to exceed a borrowing base determined at least semiannually. As of March 7, 2005, the borrowing base was $900 million. The Credit Agreement provides that in specified circumstances involving an increase in ratings assigned to the Company’s
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debt, the Company may elect for the borrowing base limitation to no longer apply to restrict available borrowings. As of March 1, 2005, the Company had an outstanding balance of $520,000,000 under its Credit Agreement See “Capital Structure — Credit Agreement”.
American Jobs Creation Act of 2004
On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”). The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations. The deduction is subject to a number of limitations and, as of March 1, 2005, uncertainty remains as to how to interpret numerous provisions of the Act. As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S., therefore if technical corrections to the Act are passed the Company may repatriate in 2005 an amount up to approximately $195.7 million of the cash and current investments held by international subsidiaries discussed in “Liquidity and Capital Resources” above. Assuming 15% of such cash is subject to tax at the U.S. statutory rate, the repatriation would be subject to a tax liability of approximately $10.2 million. This amount excludes any proceeds that will be realized from the sale of the Company’s Thailand and Hungarian operations.
Future Capital and Other Expenditure Requirements
The Company’s capital and exploration budget for 2005, which does not include any amounts that may be expended for acquisitions or any interest which may be capitalized resulting from projects in progress, was established by the Company’s Board of Directors at $345,000,000. The Company has included 226 gross wells in its 2005 capital and exploration budget, including wells to be drilled in the United States and the Kingdom of Thailand. As of March 7, 2005, the Company anticipates that its available cash and cash investments, cash provided by operating activities and funds available under its Credit Agreement will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, its authorized capital budget, and dividend payments at current levels for the foreseeable future. The declaration and amount of future dividends on the Company’s common stock will depend upon, among other things, the Company’s future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and other payments under covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.
Stock Repurchase
On January 25, 2005, the Company announced a plan to repurchase, through open market or privately negotiated transactions, not less than $275 million nor more than $375 million of its common stock. As of March 1, 2005, the Company had completed the purchase of 940,200 shares at a total cost of $41.5 million.
Other Material Long-Term Commitments
Contractual Obligations. The Company’s material contractual obligations include long-term debt, operating leases, and other contracts. Material contractual obligations for which the ultimate settlement amounts are not fixed and determinable include derivative contracts that are sensitive to future changes in commodity prices and other factors. See “Item 7A. Quantitative and Qualitative Disclosure about Market Risk”, filed as Exhibit 99.3 to this report. A summary of the Company’s known contractual obligations related to continuing operations as of December 31, 2004 are set forth on the following table:
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| | Payments due by period (in millions) | |
| | | | Less than | | 1 - 3 | | 3 - 5 | | More than | |
| | Total | | 1 Year | | Years | | Years | | 5 Years | |
Long Term Debt (a) | | $ | 858.7 | | $ | 16.5 | | $ | 33.0 | | $ | 588.0 | | $ | 221.2 | |
Operating Lease Obligations (b) | | $ | 91.0 | | $ | 8.8 | | $ | 17.6 | | $ | 17.5 | | $ | 47.1 | |
Purchase Obligations (c) | | $ | 16.3 | | $ | 1.2 | | $ | 2.5 | | $ | 2.6 | | $ | 10.0 | |
Asset Retirement Obligations (d) | | $ | 231.7 | | $ | 4.0 | | $ | 4.9 | | $ | 7.0 | | $ | 215.8 | |
Total | | $ | 1,197.7 | | $ | 30.5 | | $ | 58.0 | | $ | 615.1 | | $ | 494.1 | |
(a) Includes interest on fixed rate debt, but excludes variable rate interest expense on the Company’s bank credit facility.
(b) Operating leases principally include the Company’s office lease commitments and various other equipment rentals, including gas compressors. Where rented equipment such as compressors is considered essential to the operation of the lease, the Company has assumed that such equipment will be leased for the estimated productive life of the reserves, even if the contract terminates prior to such date. See Note 5 to the Consolidated Financial Statements.
(c) This represents firm transportation agreements representing “ship-or-pay” arrangements whereby the Company has committed to ship certain volumes of gas for a fixed transportation fee (principally from the Madden Field in Wyoming). The Company entered into these arrangements to ensure its access to gas markets and expects to produce sufficient volumes to satisfy substantially all of its firm transportation obligations.
(d) This represents the Company’s estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 11 to the Consolidated Financial Statements.
Commitments under Joint Operating Agreements. The oil and gas industry operates in many instances through joint ventures under joint operating agreements, and the Company’s operations are no exception. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator in the event that the non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses. The contractual obligations set forth above represent the Company’s working interest share of the contractual commitments that it has entered into as operator and, to the extent that it is aware, the contractual commitments entered into by the operator of projects that the Company does not operate.
Surety Bonds. In the ordinary course of the Company’s business and operations, it is required to post surety bonds from time to time with third parties, including governmental agencies, primarily to cover self insurance, site restoration, equipment dismantlement, plugging and abandonment obligations. As of December 31, 2004, the Company had obtained surety bonds from a number of insurance and bonding institutions covering certain operations in the United States in the aggregate amount of approximately $8,500,000 that are not included in the prior table. In connection with their administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee’s plugging and abandonment liabilities. The MMS reviews this information and applies certain financial tests including, but not limited to, current asset and net worth tests. The MMS determines whether each lessee is financially capable of paying the estimated costs of such plugging and abandonment liabilities. The Company must annually provide the MMS with financial information. If the Company does not satisfy the MMS requirements, it could be required to post supplemental bonds. In the past, the Company has not been required to post supplemental bonds; however, there can be no assurance that the Company will satisfy the financial tests and remain on the list of MMS lessees exempt from the supplemental bonding requirements. The Company cannot predict or quantify the amount of any such supplemental bonds or the annual premiums related thereto and therefore has not included them in the prior table, but the amount could be substantial.
Guarantees and Letters of Credit. The Company had issued performance guarantees related to the operations of its subsidiaries in Thailand. If its subsidiaries do not fulfill their contractual obligations or legal obligations under the relevant local laws, the Company could be obligated to make payments to satisfy the subsidiaries’ obligations. Most of these obligations relate to plugging, abandonment, site restoration and compliance with environmental laws. The Company also has guaranteed performance of its subsidiaries’ obligations under the FPSO lease. However, the Company’s guarantee of these obligations has not been so included. These guarantees were terminated upon the completion of the sale of the Thailand Entities on August 17, 2005. As of March 7, 2005, there were no material letters of credit that have been issued on the Company’s behalf.
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Credit Agreement and Borrowing Base Determination
Credit Agreement. The Company has a revolving credit facility (the “Credit Agreement”) that provides for a $750,000,000 revolving loan facility terminating on December 16, 2009. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base determined at least semiannually using the administrative agent’s usual and customary criteria for oil and gas reserve valuation, adjusted for incurrences of other indebtedness since the last redetermination of the borrowing base. As of March 7, 2005, the borrowing base was $900 million. The credit agreement provides that in specified circumstances involving an increase in ratings assigned to Pogo’s debt, Pogo may elect for the borrowing base limitation to no longer apply to restrict available borrowings. The next redetermination of the borrowing base is expected to occur by May 1, 2005. A significant decline in the prices that the Company is expected to receive for its future oil and gas production could have a material negative impact on the borrowing base under the Credit Agreement which, in turn, could have a material negative impact on the Company’s liquidity. If at a redetermination of the borrowing base, the lenders reduce the borrowing base below the amount then outstanding under the Credit Agreement and other senior debt arrangements, the Company must repay the excess to the lenders in no more than four substantially equal monthly installments, commencing not later than 90 days after the Company is notified of the new borrowing base. The Credit Agreement includes procedures for additional financial institutions selected by the Company to become lenders under the agreement, or for any existing lender to increase its commitment in an amount approved by the Company and the lender, subject to a maximum of $250 million for all such increases in commitments of new or existing lenders. The Credit Agreement also permits short-term swing-line loans up to $10 million and the issuance of letters of credit up to $75 million, which in each case reduce the credit available for revolving credit borrowings. As of March 1, 2005, there was $520,000,000 outstanding under the Credit Agreement.
Application of Critical Accounting Policies and Management’s Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements included in Exhibit 99.4 of this Form 8-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas revenues, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, on a periodic basis and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company’s financial statements:
Successful Efforts Method Of Accounting
The Company accounts for its oil and gas exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. In most cases, a gain or loss is recognized for sales of producing properties.
The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
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The successful efforts method of accounting can have a significant impact on the operational results reported when the Company enters a new exploratory area in hopes of finding oil and gas reserves. The initial exploratory wells may be unsuccessful and the associated costs will be expensed as dry hole costs. Seismic costs can be substantial which will result in additional exploration expenses when incurred.
Reserve Estimates
The Company’s estimates of oil and gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. The Company had upward reserve revisions equivalent to 1.05%, 3.66% and 8.17% of proved reserves during the years ended December 31, 2004, 2003 and 2002, respectively. These reserve revisions resulted primarily from improved performance from a variety of sources such as additional recoveries below previously established lowest known hydrocarbon levels, improved drainage from natural drive mechanisms, and the realization of improved drainage areas. If the estimates of proved reserves were to decline, the rate at which the Company records depletion expense would increase. Holding all other factors constant, a reduction in the Company’s proved reserve estimate of 1% would result in an annual increase in DD&A expense of approximately $2.6 million.
Impairment Of Oil and Gas Properties
The Company reviews its proved oil and gas properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company estimates the expected future cash flows from its proved oil and gas properties and compares these future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to its fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company has recognized impairment expense in 2002, 2003 and 2004. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.
Fair Values Of Derivative Instruments
The estimated fair values of the Company’s derivative instruments are recorded on the Company’s consolidated balance sheet. Historically, substantially all of the Company’s derivative instruments have represented cash flow hedges of the price of future oil and natural gas production. Therefore, while fair values of such hedging instruments must be estimated at the end of each reporting period, the related changes in such fair values are not included in the Company’s consolidated results of operations, to the extent they are expected to offset the future cash flows from oil and natural gas production. Instead, the changes in fair value of hedging instruments are recorded directly to shareholders’ equity until the hedged oil or natural gas quantities are produced and sold.
The estimation of fair values for the Company’s hedging derivatives requires substantial judgment. The Company estimates the fair values of its derivatives on a monthly basis using an option-pricing model. To utilize the option-pricing model, the Company uses various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the hedge agreements,
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and the resulting estimated future cash inflows (outflows) over the lives of the hedges are discounted using the Company’s current borrowing rates under its revolving credit facility. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differentials and interest rates. Historically, the majority of the Company’s derivative instruments have been hedges of the price of crude oil and natural gas production. The Company is not involved in any derivative trading activities.
Business Combinations/Acquisitions
In 2004, the Company grew through the acquisition of two corporations. These acquisitions were accounted for using the purchase method of accounting. Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill and other intangibles with an indefinite useful life are assessed for impairment at least annually. The Company has never recorded any goodwill in connection with its business combinations/acquisitions. However, there can be no assurance that the Company will not do so in the future.
There are various assumptions made by the Company in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, the Company prepares estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by the Company’s engineers and outside petroleum reservoir consultants. The judgments associated with the estimation of reserves are described earlier in this section. The fair value of the estimated reserves acquired in a business combination is then calculated based on the Company’s estimates of future oil, natural gas and NGL prices. The Company’s estimates of future prices are based on its own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics, such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity and trends in regional pricing differentials. Future price forecasts from independent third parties are also taken into account in arriving at the Company’s own pricing estimates. The Company’s estimates of future prices are applied to the estimated reserve quantities acquired to arrive at estimated future net revenues. For estimated proved reserves, the future net revenues are then discounted to derive a fair value for such reserves. The Company also applies these same general principles in arriving at the fair value of unproved reserves acquired in a business combination. These unproved reserves are generally classified as either probable or possible reserves. Because of their very nature, probable and possible reserve estimates are less precise than those of proved reserves. Generally, in the Company’s business combinations, the determination of the fair values of oil and gas properties requires more judgment than the estimates of fair values for other acquired assets and liabilities.
Future Development and Abandonment Costs
Future development costs include costs incurred to obtain access to proved reserves, including drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the ultimate settlement amount, inflation factors, credit adjusted discount rates, timing of settlement and changes in the political, legal, environmental and regulatory environment. The Company reviews its assumptions and estimates of future abandonment costs on an annual basis. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of SFAS 143. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Holding all other factors constant, if the Company’s estimate of future abandonment costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates were revised downward, earnings would increase due to lower DD&A expense. It would require an increase in the present value of the Company’s estimated future abandonment cost of approximately $12 million (representing an increase of approximately 16% to the Company’s December 31, 2004 asset retirement obligation) to increase the Company’s DD&A rate by $0.01 per Mcfe for the year ended December 31, 2004.
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Pension and Other Post-Retirement Benefits
Accounting for pensions and other postretirement benefits involves several assumptions including the expected rates of return on plan assets, determination of discount rates for remeasuring plan obligations, determination of inflation rates regarding compensation levels and health care cost projections. The Company develops its demographics and utilizes the work of actuaries to assist with the measurement of employee-related obligations. The assumptions used vary from year-to-year, which will affect future results of operations. Any differences among these assumptions and the results actually experienced will also impact future results of operations. An analysis of the effect of a 1% change in health care cost trends on post-retirement benefits is included in Note 9 to the Consolidated Financial Statements.
Income Taxes
For financial reporting purposes, the Company generally provides taxes at the rate applicable for the appropriate tax jurisdiction. Where the Company’s present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries. Management periodically assesses the need to utilize these unremitted earnings to finance the foreign operations of the Company. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for the Company’s operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future. See “Liquidity and Capital Resources — American Jobs Creation Act of 2004.”
Management also periodically assesses, by tax jurisdiction, the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks. Such estimates are inherently imprecise since many assumptions utilized in the assessments are subject to revision in the future.
Other Matters
Inflation. Publicly held companies are asked to comment on the effects of inflation on their business. As of March 7, 2005, annual inflation in terms of the decrease in the general purchasing power of the dollar is running well below the general annual inflation rates experienced in the past. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the dollar due to inflation, such effect is not considered significant as of March 7, 2005.
Recent Accounting Pronouncements
The Financial Accounting Standards Board (“FASB”) has issued three new pronouncements relevant to the Company’s accounting. These are Statement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS 123R”), “Share-Based Payment”, Statement of Financial Accounting Standards No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” and FASB Staff Position FAS 109-2 (“FSP FAS 109-2”), “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision Within the American Jobs Creation Act of 2004”.
SFAS 123R. SFAS 123R will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. Statement 123(R) replaces FASB Statement No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation”, and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees”. SFAS 123R is effective as of the first interim or annual reporting period that begins after June 15, 2005. The Company currently follows the provisions of SFAS 123 and the adoption of SFAS 123R is not expected to have a material effect on the Company’s financial statements.
SFAS 153. SFAS 153 was a result of an effort by the FASB and the International Accounting Standards Board (“IASB”) to improve financial reporting by eliminating certain narrow differences between their existing accounting standards. One such difference was the exception from fair value measurement in APB Opinion No. 29, Accounting for Nonmonetary Transactions, for nonmonetary exchanges of similar productive assets. SFAS 153 replaces this exception with a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date of issuance of this Statement. The adoption of SFAS 153 is not expected to have a material effect on the Company’s financial statements.
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FSP FAS 109-2. In December 2004, the FASB staff issued FSP FAS 109-2 to provide accounting and disclosure guidance for the repatriation provisions included in the Act. The Act introduced a special limited-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer. As a result, an issue has arisen as to whether an enterprise should be allowed additional time beyond the financial reporting period in which the Act was enacted to evaluate the effects of the Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying Statement 109. The following are the key points relevant to the Company’s position:
• An enterprise is allowed additional time beyond the financial reporting period of enactment to evaluate the effect of the Act without undermining the entity’s assertion that repatriation of foreign earnings is not expected within the foreseeable future.
• An enterprise should recognize the income tax effect when it decides on a plan for reinvestment or repatriation of foreign earnings. This decision may occur in stages, and each stage may occur at a different time. Also, before its plan for reinvestment or repatriation is finalized, an enterprise may decide on a range of amounts that it will repatriate. In this situation, the FSP requires recognition of the income tax effect of the lowest amount within the range.
• If an enterprise has recognized a deferred tax liability for some, or all, of its unremitted foreign earnings because it did not overcome the presumption of repatriation of foreign earnings, it should continue to presume repatriation of those earnings as well as current foreign earnings that are not expected to be indefinitely reinvested. The enterprise shall measure the income tax effects of such repatriation without the effects of the repatriation provision until it has decided on a plan for repatriation.
• An enterprise that has not yet completed its evaluation of the repatriation provision should make certain disclosures. Additional disclosures are required in the period an enterprise completes its evaluation
The Company has adopted the disclosure requirements of FSP FAS 109-2 and is currently evaluating the effects of the Act. The Company expects to be in a position to finalize its assessment shortly after passage of technical corrections to the Act.
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