ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 8 of our Consolidated Financial Statements in Item 8 of this Form 10-K.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the quarter ended December 31, 2003.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 3, 2004, there were 34,182,837 shares of common stock outstanding held by 197 holders of record. The common stock is traded on the New York Stock Exchange, or NYSE, under the symbol "WGR". The following table sets forth quarterly high and low sales prices as reported by the NYSE Composite Tape for the quarterly periods indicated.
We paid annual dividends on our common stock aggregating $0.20 per share during the years ended December 31, 2003 and 2002. We have declared a dividend of $0.05 per share of common stock for the quarter ending March 31, 2004 to holders of record as of that date. Declarations of dividends on our common stock are within the discretion of the board of directors. In addition, our ability to pay dividends on our common stock is restricted by covenants in our financing facilities, the most restrictive of which is in our subordinated note indenture, and that covenant prohibits declaring or paying dividends that exceed, in the aggregate, the sum of $20 million plus 50% of our consolidated net operating income (as defined in the indenture) earned after July 1, 1999 (or minus 100% if a net loss) plus the aggregate net cash proceeds received after July 1, 1999 from the sale of any stock. At December 31, 2003, availability under this covenant was approximately $76.8 million.
Equity Compensation Plan Information
The following table summarizes our equity compensation plans under which securities may be issued as of December 31, 2003. The only types of equity compensation plans that we have are plans that authorize the granting of options to purchase shares of our common stock.
A description of the equity compensation plans that were not approved by the security holders is as follows.
1999 Non-Employee Directors Stock Option Plan. Effective March 1999, our board of directors adopted a stock option plan that authorized the granting of options to purchase 15,000 shares of our common stock to non-employee directors. During 1999, the board approved grants of options covering a total of 15,000 shares of our common stock to several board members. The exercise price of the stock underlying each option was the average closing price for the ten days prior to the grant. Under this plan, options covering up to 331/3% of the underlying shares are exercisable on each anniversary from the date of grant and the director must exercise the option within five years of the date each option vests. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.
Chief Executive Officer and President's Plan. Pursuant to the employment agreement, dated October 15, 2001, and the stock option agreement, dated as of November 1, 2001, between us and Peter A. Dea, our CEO and President, we granted non-qualified stock options to Mr. Dea for the purchase of 300,000 shares of our common stock. The exercise price of the options was equal to $5.00 below the closing price per share on the effective date of his employment agreement. The stock options are subject to the conditions of the agreements and vest equally over four years and must be exercised within five years of the date on which they vest. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated historical financial and operating data for Western. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. The data for the three years ended December 31, 2003, 2002 and 2001 should be read in conjunction with our Consolidated Financial Statements and the Notes thereto included elsewhere in this Form 10-K. The selected consolidated financial data for the years ended December 31, 2000 and 1999 are derived from our audited historical Consolidated Financial Statements. See also Item 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 2003, 2002 and 2001. Certain prior year amounts have been reclassified to conform to the presentation used in 2003. Reference should also be made to our Consolidated Financial Statements and related Notes thereto and the Selected Financial Data included elsewhere in this Form 10-K.
Company Overview
Business Strategy-Maximizing the value of our existing core assets is the focal point of our business strategy. Our core assets are our fully integrated upstream and midstream assets in the Powder River and Greater Green River Basins in Wyoming and Colorado and our midstream operations in west Texas, Oklahoma and New Mexico. Our long-term business plan is to increase stockholder value by: (i) doubling proven reserves and equity production of natural gas from the levels achieved in 2001 over a five year period; (ii) meeting or exceeding throughput projections in our midstream operations; and (iii) optimizing annual returns.
Industry and Company Overview-In North America, our industry has experienced several consecutive years of declining natural gas production. Most of the major gas producing areas, such as the Gulf of Mexico, are mature and are in production decline. We are concentrating our efforts in the Rocky Mountain gas producing basins where there are estimated to be large quantities of undeveloped gas. The U.S. government largely retains the mineral rights to these undeveloped reserves; accordingly, the development and production of these reserves require permits from several governmental agencies including the BLM. We are well positioned for future production growth with a large inventory of undeveloped drilling locations in the Powder River and Greater Green River Basins to meet the growing demand for clean burning natural gas. In addition, our experience and technical expertise position us to acquire new opportunities to develop natural gas in the Rocky Mountain region. Our challenges will be to accomplish these goals with the difficulties encountered by the industry in obtaining the necessary permits from the BLM. We believe that our technical expertise in developing environmentally responsible solutions to the problems encountered in the development of gas reserves will be a competitive advantage in overcoming these challenges.
Our operations are conducted through the following four business segments:
Upstream-We explore for, develop and produce natural gas reserves independently and to enhance and support our existing gathering and processing operations. Our producing properties are primarily located in the Powder River and Green River Basins of Wyoming. These plays are low-risk, long-lived development projects. These provide us with the opportunity to steadily increase our production volume at low operating and finding and development costs. In 2003 our production grew 10% compared to 2002 levels and far exceeded the industry average for 2002 of a three percent decline in production. Our 2003 production level represented a 47% increase towards meeting our goal of doubling our equity production of natural gas. Also benefiting us in 2003 were higher prices received for natural gas. As a result operating income in this segment increased by 53% to $113.5 million in the year ended December 31, 2003 compared to 2002. At December 31, 2003, we had a total of 685 Bcfe of proved natural gas reserves in our various operating areas. Our business strategy is to double our proven reserves from those in place at December 31, 2001 by the end of 2006. At December 31, 2003, we are 44% toward meeting this goal of doubling proved reserves.
We are also actively seeking to add additional upstream core projects that are focused on Rocky Mountain natural gas. We will utilize our expertise in exploration and low-risk development of tight-gas sands, coal bed methane and fractured shale plays to evaluate acquisitions of either additional
leaseholds, proven and undeveloped reserves or companies with operations focused in the Rockies. Toward this goal, we have acquired the drilling rights on approximately 340,000 net acres, in the northeastern area of the Denver-Julesburg Basin in northeast Colorado and southwest Nebraska.
Gathering, Processing and Treating-Our core operations are in well-established areas such as the Permian, Anadarko, Powder River, Greater Green River, and San Juan Basins. We connect natural gas from gas and oil wells to our gathering systems for delivery to our processing or treating plants under long-term contracts. At our plants we process natural gas to extract NGLs and we treat natural gas in order to meet pipeline specifications. We provide these services to major oil and gas companies, to independent producers of various sizes and for our own production. We believe that our low cost of operations, our high on-line time, and our safety records are key elements in our ability to compete effectively and provide service to our customers. Our expertise in gathering, processing and treating operations can enhance the economics of developing new upstream projects.
This segment of our operations has provided a stream of operating profit that is available for reinvestment into other projects or other segments of our business. In 2003, we realized operating profit from this segment of $126.6 million, which is a 35% increase from 2002. This segment benefited from significantly higher product prices in 2003 compared 2002 and from increased drilling activity by third-party producers behind our facilities. Overall throughput in our facilities during 2003 increased 13% from 2002 and averaged a total of 1.3 Bcf per day.
Transportation-In the Powder River Basin, we own one interstate pipeline, MIGC, and one intrastate pipeline, MGTC, which transport natural gas for producers and energy marketers under fee schedules regulated by state or federal agencies. In 2003, we realized operating profit from this segment of $11.6 million, which is a 29% decrease from 2002. The decrease in profit in this segment is due to lower interruptible transportation volume in 2003 as more gas was transported out the basin through other pipelines.
Marketing-Our gas marketing segment is an outgrowth of our gas processing and upstream activities. One of the primary goals of our gas marketing operations is the preservation and enhancement of the value received for our equity volumes of natural gas. This goal is achieved through the use of hedges on the production of our equity natural gas and NGLs and through the use of firm transportation capacity. We also buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. These third-party sales, our firm transportation capacity on interstate pipelines and our gas storage positions, combined with the stable supply of gas from our facilities and production, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods. In order to protect the profitability of this segment, we continually monitor and review credit exposure to our marketing counterparties. During 2003, we experienced no uncollectible accounts.
In 2003, we realized operating profit from this segment of $31.4 million, which is a 14% decrease from 2002. The decrease in operating profit is primarily due to lower profitability on transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. New transportation capacity added in 2003 out of the Rocky Mountain region has resulted in a decrease in the difference between the prices for natural gas received in this region compared to the prices received in the Mid-Continent marketing area.
Results of Operations
Year ended December 31, 2003 compared to year ended December 31, 2002
(000s, except per share amounts and operating data)
Net income increased $33.6 million for the year ended December 31, 2003 compared to 2002. The increase in net income was primarily attributable to a significant increase in gas and NGL prices in 2003 compared to last year. This increase in prices was supplemented by increased equity production from the Powder River Basin CBM project and the Green River Basin. Partially offsetting the increase in net income in the year ended December 31, 2003 was a $6.7 million after-tax loss from the cumulative effect of a change in accounting principle from the adoption of SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003.
Revenues from the sale of gas increased $344.3 million to $2,463.0 million for the year ended December 31, 2003 compared to 2002. This increase was primarily due to an increase in product prices, which more than offset a decrease in sales volume in 2003. Average gas prices realized by us increased $2.02 per Mcf to $4.94 per Mcf for the year ended December 31, 2003 compared to 2002. Included in the calculation of the realized gas price were approximately $23.9 million of losses recognized in the year ended December 31, 2003 related to futures positions on equity gas volumes. We have entered into additional futures positions for approximately half of our equity gas for 2004. See further discussion in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." Average gas sales volumes decreased 626 MMcf per day to 1,362 MMcf per day for the year ended December 31, 2003 compared to 2002. This decrease was due to a reduction in third party sales volume resulting from the increase in product prices and an intentional effort to reduce related credit exposure.
Revenues from the sale of NGLs increased approximately $36.6 million to $346.1 million for the year ended December 31, 2003 compared to 2002. This increase is primarily due to a significant increase in product prices, which was partially offset by a reduction in third-party sales volumes. Average NGL prices realized by us increased $0.16 per gallon to $0.58 per gallon for the year ended December 31, 2003 compared to 2002. Included in the calculation of the realized NGL price were approximately $11.4 million of losses recognized in the year ended December 31, 2003 related to futures positions on equity NGL volumes. We have entered into additional futures positions for approximately half of our equity NGL production for 2004. See further discussion in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." Average NGL sales volumes decreased 375 MGal per day to 1,635 MGal per day for the year ended December 31, 2003 compared to 2002.
Product purchases increased by $299.3 million for the year ended December 31, 2003 compared to 2002 as a result of the significant increase in commodity prices. Overall, combined product purchases as a percentage of sales of all products remained relatively constant at approximately 89% for both 2003 and 2002.
Plant and transportation operating expense increased by $6.8 million for the year ended December 31, 2003 compared to 2002. The increase was primarily due to increased throughput at our facilities, the acquisition of several gathering systems in the first quarter of 2003 and additional leased compression in the Powder River Basin coal bed development. Also contributing to this increase were the fees paid to other companies, primarily Rendezvous, for gas gathering services. Rendezvous is a 50%-owned entity that delivers gas to our Granger Complex. Rendezvous is accounted for under the equity method, and our share of its gathering revenues is reflected in Earnings from equity investments.
Oil and gas exploration and production expenses increased by $18.2 million for the year ended December 31, 2003 compared to 2002. In our operating areas, the significant increase in residue gas prices in 2003 resulted in substantially higher severance tax expenses. Overall, lease-operating expense, or LOE, for the year ended December 31, 2003 increased by approximately $0.04 per Mcfe compared to 2002 and averaged $0.46 per Mcfe. The increase in lease-operating expense per Mcfe is primarily due to unsuccessful well expenses of $1.8 million in 2003.
Depreciation, depletion and amortization decreased by $3.1 million for the year ended December 31, 2003 as compared to 2002. This decrease was the result of revisions to the operating lives, and salvage values, of our operating assets partially offset by increased production in the Powder River Basin and additional depreciation in 2003 from new projects. The revisions to the operating lives and salvage values of our operating assets were the result of analysis performed in connection with the adoption of SFAS No. 143 on January 1, 2003 and were treated as a revision of an estimate and are accounted for on a prospective basis.
Selling and administrative expenses increased by approximately $4.6 million in the year ended December 31, 2003 as compared to 2002. This increase was the result of higher compensation expenses due to an increased employee count in 2003 resulting from our growing exploration and production operations, and a modification in 2003 to our incentive compensation plan to pay this compensation on a current basis as opposed to a vesting schedule used in prior years. Also contributing to the increase were higher professional fees resulting from litigation concluded in 2003 and our ongoing research associated with the CFTC investigation of our price reporting to trade publications. Partially offsetting these increases were fewer charges for doubtful accounts in 2003 as compared to 2002.
In 2003, in order to properly align our hedged volumes of natural gas to our forecasted equity production, we discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings from Accumulated other comprehensive income.
Cash Flow Information
Cash flows from operating activities increased by $117.6 million in 2003 compared to 2002. This increase was primarily due to an increase in net income in 2003 compared to the prior year and the timing of cash receipts and payables.
Cash flows used in investing activities increased by $91.3 million in 2003 compared to 2002. This increase was primarily due to a higher level of capital expenditures.
Cash flows used in financing activities increased by $4.8 million in 2003 compared to 2002. This increase was due to increased cash flows from operating activities, which was used to reduce our long-term debt.
Other Information
Acquisition and Disposition of Gathering Systems. Effective February 1, 2003, we acquired several gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River and Wind River did not integrate directly into our existing systems, and accordingly these systems were sold. During the year ended December 31, 2003, the income, if any, generated by the assets sold was immaterial for separate presentation as a discontinued operation.
Acquisition of Sand Wash Properties. In August 2003, through the acquisition of the stock of a private corporation for $12.9 million, we acquired additional reserves, production and acreage in this area. The assets of this private entity consisted primarily of the remaining interests in various Sand Wash properties that we operate. This acquisition included approximately 11 billion cubic feet equivalent, or Bcfe, of proved reserves, 2.1 MMcfe per day of production and approximately 11,000 net acres under lease.
Segment Information
Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $126.6 million for the year ended December 31, 2003 as compared to $93.6 million in 2002. The increase in operating profit in this segment in 2003 is primarily due to higher commodity prices, increased gathering volumes and the acquisition of several gathering systems in February 2003.
Exploration and Production. The Exploration and Production segment realized segment-operating profit of $113.5 million for the year ended December 31, 2003 compared to $74.1 million in 2002. The increase in operating profit in this segment in 2003 was primarily due to substantially higher natural gas prices and production volume growth from the Powder River Basin CBM area and the Pinedale Anticline.
Marketing. The Marketing segment realized segment-operating profit of $31.4 million for the year ended December 31, 2003 compared to $36.4 million in 2002.
The decrease in the marketing margin is primarily due to transactions associated with our firm transportation capacity from the Rocky Mountain region to the Mid-Continent. Our firm transportation allows us to purchase gas in the Rocky Mountain region for resale in the higher priced Mid-Continent markets. In the second quarter of 2003, additional transportation capacity out of the Rocky Mountain region became operational, which reduced the price difference between the two regions. We expect that the reduced margins will continue in future periods. There is no assurance that the margins we realized on the sale of gas in 2003 will continue in the future, or that we will continue to originate the same amount of transactions in future years.
Transportation. The Transportation segment realized segment-operating profit of $11.6 million for the year ended December 31, 2003 compared to $16.3 million in 2002. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin. The decrease in profit in this segment is due to lower interruptible transportation volume in 2003 as more gas was transported out the basin through other pipelines.
Year ended December 31, 2002 compared to year ended December 31, 2001
(000s, except per share amounts and operating data)
Net income decreased $45.0 million for the year ended December 31, 2002 compared to 2001. The decrease in net income was primarily attributable to significantly lower gas and NGL prices in this period as compared to the prior year and lower margins per unit earned on our sales of natural gas. These decreases more than offset increased production from the Powder River Basin CBM development.
Revenues from the sale of gas decreased $747.6 million to $2.1 billion for the year ended December 31, 2002 compared to 2001. This decrease was primarily due to a decline in product prices, which more than offset an increase in sales volume in the year ended December 31, 2002. Average gas prices realized by us decreased $1.05 per Mcf to $2.92 per Mcf in the year ended December 31, 2002 compared to 2001. Included in the realized gas price were approximately $28.1 million of gains recognized in the year ended December 31, 2002 related to futures positions on equity gas volumes. Average gas sales volumes increased minimally to 1,988 MMcf per day in the year ended December 31, 2002 compared to 2001.
Revenues from the sale of NGLs decreased approximately $114.6 million to $309.5 million in the year ended December 31, 2002 compared to 2001. This decrease was due to a reduction in product prices and to a reduction in sales volume. Average NGL prices realized by us decreased $0.07 per gallon to $0.42 per gallon in the year ended December 31, 2002 compared to 2001. Included in the realized NGL price were approximately $8.2 million of losses recognized in the year ended December 31, 2002 related to futures positions on equity NGL volumes. Average NGL sales volumes decreased 337 MGal per day to 2,010 MGal per day in the year ended December 31, 2002 compared to 2001.
Product purchases decreased by $829.8 million for the year ended December 31, 2002 compared to 2001 primarily as a result of the decrease in commodity prices. Overall, combined product purchases as a percentage of sales of all products decreased to 89% for the year ended December 31, 2002 from 91% for 2001. The decrease in the product purchase percentage for the year ended December 31, 2002 versus 2001 resulted from a decrease in product prices and an increase of sale of our production from the Powder River Basin development.
In the year ended December 31, 2002, we expensed a total of $1.6 million for doubtful accounts, primarily due to the bankruptcy filing of a large mid-western co-op during the year. This compared to
an expense of $2.7 million for doubtful accounts in 2001. These charges are not included in the calculation of the marketing margins and are reported in Selling and administrative expenses.
Plant and transportation operating expense increased by $6.0 million in the year ended December 31, 2002 compared to 2001. This increase was primarily due to additional leased compression, repair and maintenance and labor costs in the Powder River Basin coal bed development and higher property tax expenses at our plant facilities.
Oil and gas exploration and production expenses increased by $6.5 million in the year ended December 31, 2002 as compared to 2001. In our operating areas, the significant reduction in residue gas prices in the 2002 periods resulted in substantially lower severance tax expenses. These reductions were substantially offset by increased lease operating expenses, or LOE, in the Powder River Basin coal bed development. Overall, LOE averaged $0.42 per Mcf in the year ended December 31, 2002. LOE in the Powder River Basin coal bed development averaged $0.45 per Mcf in the year ended December 31, 2002. This represented increases of $0.06 per Mcf and $0.03 per Mcf from the comparable periods in 2001, respectively. The increases were substantially due to higher utility charges, increased use of leased generators, increased labor charges and prior period adjustments for operating supplies, utilities and technical supervision billed to us by the well operator. The increased LOE in 2002 were substantially offset by lower severance taxes resulting from the significant reduction in residue gas prices in 2002 as compared to 2001.
Selling and administrative expenses increased by $1.6 million in the year ended December 31, 2002 as compared to 2001, due to higher health insurance costs and higher compensation expenses.
Depreciation, depletion and amortization increased by $12.8 million in the year ended December 31, 2002 as compared to 2001 primarily as a result of our increasing operations in the Powder River Basin CBM development.
The provision for income taxes increased to a 37.3% effective rate for the year ended December 31, 2002 from 37.1% in 2001. This change is due to increased sales of third-party product in states with higher corporate tax rates and in Canada.
Cash Flow Information
Cash flows from operating activities decreased by $22.1 million in the year ended December 31, 2002 compared to 2001. This reduction was primarily due to a decrease in net income in 2002 compared to the prior year and the timing of cash receipts and payables.
Cash flows used in investing activities decreased by $25.9 million in the year ended December 31, 2002 compared to 2001. This decrease was primarily due to a reduction in capital expenditures.
Cash flows used in financing activities increased by $3.6 million in the year ended December 31, 2002 compared to 2001. This increase was due to the application of the proceeds received in the sale of our Toca Processing facility in 2002 to reduce the amounts outstanding under our Revolving Credit Facility.
Other Information
Toca Processing Facility. In June 2002, we entered into an agreement for the sale of our Toca processing facility in Louisiana. This sale closed in September 2002. The sale price was $32.2 million, subject to accounting adjustments, and resulted in a pre-tax loss of approximately 230,000. The purchase price included a natural gas processing plant with a capacity of 160 million cubic feet per day and a fractionator that can separate 14,200 barrels per day of mixed natural gas liquids into propane, normal butane, iso-butane and natural gasoline. The sale also includes NGL storage as well as truck, rail and barge loading facilities, which support the complex. During the year ended December 31, 2002,
this facility generated net after-tax earnings of approximately $683,000, or $.02 per share of common stock, respectively. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on our Revolving Credit Facility. At December 31, 2002, the remaining amount of $17.2 million was on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction and was reflected on the Consolidated Balance Sheet under the caption Other current assets. These funds, along with additional amounts drawn on our Revolving Credit Facility, were used in a February 2003 acquisition of several gathering systems.
Bethel Treating Facility. In December 2000, we signed an agreement for the sale of all the outstanding stock of our wholly owned subsidiary, Pinnacle Gas Treating, Inc., or Pinnacle, for $38.0 million. The only asset of this subsidiary was a 300 MMcf per day treating facility and 86 miles of associated gathering assets located in east Texas. The sale closed in January 2001 and resulted in a net pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.
Segment Information
Gas Gathering, Processing and Treating. The Gas Gathering, Processing and Treating segment realized segment-operating profit of $93.6 million for the year ended December 31, 2002 as compared to $134.3 million in 2001. The decrease in operating profit in this segment in 2002 is primarily due to lower commodity prices, partially offset by gains in equity hedges.
Exploration and Production. The Exploration and Production segment realized segment-operating profit of $74.1 million for the year ended December 31, 2002 compared to $64.2 million in 2001. The increase in operating profit in this segment in 2002 was primarily due to production volume growth from the Powder River Basin CBM area and the Pinedale Anticline, substantially offset by lower commodity prices.
Marketing. The Marketing segment realized segment-operating profit of $36.4 million for the year ended December 31, 2002 compared to $47.4 million in 2001. The margins earned from the sale of third-party natural gas averaged $0.04 and $0.06 per Mcf in the years ended December 31, 2002 and 2001, respectively. The decrease in margin for 2002 compared to 2001 primarily resulted from reduced margins associated with the mark-to-market of forward transactions in the current year versus the prior year. This reduction in margin is primarily the result of our electing hedge accounting on several of our transactions in 2002 utilizing our firm transportation capacity and fewer long-dated transactions utilizing our transportation capacity in place at the end of 2002 compared to 2001. Under hedge accounting, the margin to be realized on a transaction is recorded in the month the transportation capacity is used, and under mark-to-market accounting, the anticipated margin on a transaction to be realized over the term of the transaction is recorded in the month of origination.
Transportation. The Transportation segment realized segment-operating profit of $16.3 million for the year ended December 31, 2002 compared to $16.3 million in 2001. The transportation segment includes the results from the MIGC and MGTC pipelines in the Powder River Basin.
Critical Accounting Estimates
The application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an interpretation and implementation of existing rules, and the use of judgment, to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules is critical. For further details on our accounting policies, and the estimates, assumptions and judgments we use in applying these
policies and a discussion of new accounting rules, see Note 2 of the Notes to Consolidated Financial Statements.
Use of Estimates. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. However, actual results may differ significantly from the estimates used. Any effects on our business, financial position or results of operations resulting from revisions to these estimates will be recorded in the period in which the facts that necessitate a revision become known. Although there are a number of areas where we use estimates, what we believe to be the most significant ones are discussed below.
Property and Equipment. Depreciation on our property and equipment is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years. Useful lives are determined based on the shorter of our estimate of the life of the equipment or our estimate of the reserves serviced by the equipment. Among other factors, the estimates consider our experience with similar assets and technical analysis of the reserves. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production. If the actual lives of the equipment or the reserves serviced by the equipment were less than we originally estimated, we may be required to record a loss upon retirement of a specific asset.
Oil and Gas Reserves, Properties and Equipment. We follow the successful efforts method of accounting for oil and gas exploration and production activities. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves. The units of production method is sensitive to the determination of proved reserves. To the extent the reserves are modified, the depletion determined under the units of production method will be increased or decreased on a prospective basis.
Our reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves, the projection of future rates of production and the timing of development expenditures. The accuracy of these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated.
Asset Retirement Obligations. We use significant judgment in estimating our future liability for asset retirement. We evaluate each asset and in some cases individual components of assets to determine and estimate the future cost and timing of retiring those assets. The estimate of the future cost is then discounted back to the present and recorded as a liability. This liability will vary based upon the probability, timing and the extent of remediation necessary to reclaim those facilities, the discount factor used in those determinations and the projected costs of the remediation. We evaluate these estimates on an ongoing basis and modify our assumptions as appropriate.
Impairment of Long-Lived Assets. If changes in the expected performance of an asset occur, or if overall economic conditions warrant, we will review our assets to determine their economic viability.
In accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long Lived Assets", assets are to be evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. Accordingly, our review is completed at the plant facility, the related group of plant facilities or the oil and gas producing field or producing coal seam level. In order to determine whether an impairment exists, we compare the net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the associated reserves. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. This analysis is sensitive to, among other things; management's expectation of commodity prices, operating costs, drilling plans, production rates and the evaluation in determining asset groupings for which cash flows are largely independent of the cash flows of other assets.
In the fourth quarter of 2003, we conducted a review of our oil and gas producing properties, which included an evaluation of the geologic formations and production history for these properties. This review indicated that the cash flows from individual wells in our operating areas were not largely independent of the cash flows of other wells producing in the same field or coal seam. As a result of this review, we redefined the asset groupings to a field wide analysis for impairment for the Jonah, Pinedale and Sand Wash Basins and to a grouping of all wells drilled into related coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment was necessary for
the year ended December 31, 2003 and it was determined that none of these asset groups were impaired. In addition, while we did not recognize any impairment of our producing properties in the years ended December 31, 2002 or 2001 under the asset groupings utilized in those years, a reevaluation of those years using our new asset groups also did not result in an impairment of our producing properties.
Identification of Derivatives and Mark to Market Valuations. The determination of which contractual instruments meet the definition of a derivative under accounting rules is subject to differing interpretations as is the valuation of those derivatives. Management uses its judgment to analyze all contracts to determine whether or not they qualify as derivatives and to determine their value. A specific area in which management's judgment is required includes identifying contracts meeting the criteria for exclusions from derivatives treatment, market liquidity, and market valuation. This analysis is sensitive to commodity prices, outside market factors and management's intent upon entering into these contracts.
Recently Issued Accounting Pronouncements. We continually monitor and revise our accounting policies as new rules are issued. At this time, there are several new accounting pronouncements that have recently been issued, but not yet adopted, which will have an impact on our accounting when these rules become effective in 2004. The following pronouncements have been issued but not yet adopted.
SFAS No. 141 and SFAS No. 142. SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Intangible Assets" were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002. SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Consolidated Balance Sheet. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangibles would be included in the Notes to Consolidated Financial Statements. Historically, we have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the Oil and gas properties and equipment, even after SFAS No. 141 and No. 142 became effective.
This interpretation of SFAS No. 141 and No. 142 described above would only affect the Consolidated Balance Sheet classification of oil and gas leaseholds. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies".
At December 31, 2003, we had undeveloped leaseholds of $55.9 million that would be classified on the Consolidated Balance Sheet as "intangible undeveloped leaseholds" and developed leaseholds of $31.7 million that would be classified as "intangible developed leaseholds" if the interpretation currently being considered was applied. We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
FIN 46. In January 2003, the FASB issued Interpretation No. 46, or "FIN 46", "Consolidation of Variable Interest Entities." FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included
in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, must be adopted at the beginning of the first quarter of 2004. We did not create any VIEs after January 31, 2003 and we are continuing to evaluate the impact of FIN 46 on any VIEs created prior to that date and will adopt this pronouncement as required.
Liquidity and Capital Resources
Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek additional or alternative financing sources. Product prices, hedges of equity production, sales of inventory, the volumes of natural gas processed by our facilities, the volume of natural gas produced from our producing properties, the margin on third-party product purchased for resale, as well as the timely collection of our receivables are all expected to have significant influences on our future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing results, efficient operation of our facilities and our ability to obtain financing at favorable terms.
During the past several years, we have been successful in developing additional reserves of natural gas and increasing our equity natural gas production. However, the overall level of drilling and production associated with our producing properties will depend upon, among other factors, the price for gas, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, and the issuance of drilling and water disposal permits, none of which is entirely within our control. Any reduction in the levels of exploration, development and production by us or a significant reduction in natural gas prices could have a material adverse effect on our financial condition, results of operations and cash flows.
Although some of our plants have experienced natural declines in dedicated reserves, overall we have been successful in connecting additional reserves to more than offset these declines. However, the overall level of drilling associated with our plant facilities will depend upon, among other factors, the prices for oil and gas, the drilling budgets of third-party producers, availability of transportation capacity to market centers, the energy and environmental policy and regulation by governmental agencies, the pace at which drilling permits are received, and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities. Any prolonged reduction in prices for natural gas and NGLs may depress the levels of exploration, development and production by third-parties. Lower levels of these activities could result in a corresponding decline in the demand for our gathering, processing and treating services. A reduction in any of these activities could have a material adverse effect on our financial condition, results of operations and cash flows.
We believe that the amounts available to be borrowed under the revolving credit facility, together with net cash provided by operating activities, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third-parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or may use a combination of alternatives. While
we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing.
During 2003, we entered into an amended and restated revolving credit facility and utilized a portion of that facility to fund $43.3 million in scheduled payments on the master shelf agreement discussed below. We believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet scheduled principal repayments during 2004 of $35.0 million under the master shelf agreement and our projected preferred stock dividend requirements during 2004.
We have effective shelf registration statements filed with the SEC for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which those securities are convertible, and $62 million of debt securities, preferred stock or common stock. These shelf registrations allow us to access the debt and equity markets.
Preferred Stock Redemption. During the fourth quarter of 2003, we issued two notices of redemption for a total of 1,500,000 shares of our $2.625 cumulative convertible preferred stock. The holders of these shares had the right to convert them into shares of our common stock in lieu of receiving the redemption price in cash. In total, we issued an additional 1,840,333 shares of common stock and paid $1.9 million in cash proceeds to complete these redemptions. After completing these redemptions, we have a total of 1,252,943 shares of our $2.625 cumulative convertible preferred stock outstanding and, assuming no further redemption, we would anticipate paying in 2004 a total of $3.3 million in preferred dividends.
Sources and Uses of Funds. Our sources and uses of funds for the year ended December 31, 2003 are summarized as follows (dollars in thousands):
Capital Investment Program. We currently anticipate capital expenditures in 2004 of approximately $243.5 million. The 2004 capital budget is a 20% increase over the amount expended in 2003. This increase is the result of an expected increase in drilling activity in each of our upstream areas and additional drilling activity by third party producers whose acreage is dedicated to our midstream facilities. Overall, capital expenditures in the Powder River Basin CBM development and in southwest Wyoming operations represent 42% and 40%, respectively, of the total 2004 budget. Due to drilling and regulatory uncertainties that are beyond our control, we can make no assurance that our capital
budget for 2004 will not change. This budget may be increased to provide for acquisitions if approved by our board of directors.
The 2004 capital budget and our capital expenditures during the year ended December 31, 2003, which totaled approximately $203.1 million, are presented in the following table (dollars in thousands).
*Includes $14.4 million and $11.7 million in 2004 and 2003, respectively, for maintaining existing facilities.
Contractual Commitments and Obligations
Contractual Cash Obligations. A summary of our contractual cash obligations as of December 31, 2003 is as follows (dollars in thousands):
Guarantee of Fort Union Project Financing. We own a 13% equity interest in Fort Union Gas Gathering, L.L.C., or Fort Union, and are the construction manager and field operator. Fort Union gathers and treats natural gas in the Powder River Basin in northeast Wyoming. Initial construction and any expansions of the gathering header and treating system have been project financed by Fort Union. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis, resulting in our guarantee of $5.5 million of the debt of Fort Union at December 31, 2003. Our requirement to fund under this guarantee would be reduced by the value of assets held by Fort Union. This guarantee is not reflected on our Consolidated Balance Sheet.
Operating Leases. In the ordinary course of our business operations, we enter into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, we have entered into operating leases for compression equipment. Payments made on these
leases are a component of operating expenses and are reflected on the Consolidated Statement of Operations and, as operating leases, are not reflected on our Consolidated Balance Sheet. These leases have terms ranging from one month to ten years with return or fair market purchase options available at various times during the lease. If we were to exercise the purchase options on all the leased equipment, these purchase options would require the capital expenditure of approximately $37.0 million between 2007 and 2012.
Firm Transportation Capacity and Gathering Agreements. Access to firm transportation is also a significant element of our business strategy. Firm transportation ensures that our equity production has access to downstream markets and allows us to capture incremental profit when pricing differentials between physical locations occur. As of December 31, 2003, we had contracts for approximately 610 MMcf per day of firm transportation. This amount represents our total contracted amount on many individual pipelines. In many cases it is necessary to utilize sequential pipelines to deliver gas into a specific sales market. In total, we have the capacity to transport 172 MMcf per day of gas from the Rocky Mountain area to the Mid-Continent. This utilizes a total of approximately 376 MMcf per day of firm capacity on three separate pipelines. The total rate under these long-term contracts to transport this gas to the Mid-Continent from the southern Powder River Basin approximates $0.35 per Mcf. Our remaining firm capacity consists of 99 MMcf per day to markets within the Rocky Mountains and 135 MMcf per day contracted in various other markets throughout the country. In addition, we hold 83 MMcf per day of firm gathering capacity on the Fort Union gathering line. These agreements are not reflected on our Consolidated Balance Sheet.
A portion of this firm transportation capacity was contracted for use in our Marketing operations. For example, our Marketing segment purchases gas in the Rocky Mountain region, transports this gas utilizing its 56 MMcf per day of our firm transportation capacity to the Mid-Continent, and resells the gas to various markets. During the year ended December 31, 2003, these types of transactions have been profitable as the price difference, or basis, between the Rocky Mountain and Mid-Continent regions has exceeded the cost of transportation. The fixed fees associated with our existing contracts for firm transportation capacity during 2004 will average approximately $0.16 per Mcf per day. The associated contract periods range from one month to fourteen years. Under firm transportation contracts, we are required to pay the fees associated with these contracts whether or not the transportation is used.
Firm Storage Capacity Agreements. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and to capture seasonal price differentials. As of December 31, 2003, we had contracts in place for approximately 16.3 Bcf of storage capacity at various third-party facilities. Of the total storage capacity under contract, approximately 7.7 Bcf is under contract to our Canadian subsidiary, WGR Canada, Inc., and Western guarantees the subsidiary's performance under these contracts. This subsidiary is wholly owned by us and fully consolidated in our financial statements.
The fees associated with these contracts in 2004 will average $0.53 per Mcf of annual capacity. The associated contract periods at December 31, 2003 have an average term of twenty-nine months. At December 31, 2003, we held gas in our contracted storage facilities and in imbalances of approximately 12.7 Bcf at an average cost of $4.64 per Mcf compared to 15.1 Bcf at an average cost of $2.72 per Mcf at December 31, 2002. These positions are for storage withdrawals within the next twelve months. At the time we place product into storage, we contract for the sale of that product, physically or financially, and do not speculate on the future value of the product. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.
From time to time, we lease NGL storage space at major trading locations to facilitate the distribution of products. At December 31, 2003, we held NGLs in storage at various third-party facilities of 2,989 MGal, consisting primarily of propane and ethane, at an average cost of $0.30 per
gallon compared to 2,755 MGal at an average cost of $0.25 per gallon at December 31, 2002. These agreements for storage capacity are not reflected on our Consolidated Balance Sheet.
Long-term Debt
Revolving Credit Facility. At December 31, 2003, $94.0 million was outstanding under our existing four-year, $300 million revolving credit facility. This facility matures in April 2007. Loans made under this facility are secured by a pledge of the capital stock of our significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. The facility contains a provision that requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to a debt rating on the revolving credit facility of Ba3 or lower by Moody's Investors Service, Inc., or Moody's, or the reduction to a debt rating on the revolving credit facility of BB- or lower by Standard & Poor's Rating Services, a division of The McGraw-Hill Companies, Inc., or S&P. This facility has been rated Ba1 by Moody's and BB+ by S&P.
The borrowings under the credit facility bear interest at Eurodollar rates or a base rate, as requested by us, plus an applicable percentage based on our debt to capitalization ratio. The base rate is the agent's published prime rate. We also pay a quarterly facility fee ranging between 0.30% and 0.50%, depending on our debt to capitalization ratio. This fee is paid on the total commitment. At December 31, 2003, the interest rate payable on borrowings under this facility was approximately 2.9%.
Under the credit facility, we are subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; maintaining a senior debt to capitalization ratio of not more than 40%; and maintaining a ratio of EBITDA, as defined in the credit facility, to interest and dividends on preferred stock over the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005.
The credit facility ranks equally with borrowings under our master shelf agreement with The Prudential Insurance Company.
Master Shelf Agreement. Amounts outstanding under the master shelf agreement with The Prudential Insurance Company of America at December 31, 2003 are as indicated in the following table (dollars in thousands):
Our borrowings under the master shelf agreement are secured by a pledge of the capital stock of our significant subsidiaries, some of which have also provided a guaranty of payments we owe under the facility. The master shelf requires us to secure loans under the facility with 75% of our oil and gas reserves. This provision would only be triggered in the event of a reduction to the debt rating on the revolving credit facility of Ba3 or lower by Moody's or the reduction to the debt rating on the revolving credit facility of BB- or lower by S&P.
Under our master shelf agreement, we are subject to a number of covenants, including: maintaining a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA, as defined
in the master shelf agreement, to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005; and maintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.
In the fourth quarter of 2003, we utilized funds available under the revolving credit facility to fund $33.3 million in scheduled payments under the master shelf agreement, and in 2004 we will make scheduled payments totaling $35.0 million on this facility. We intend to fund these repayments with funds available under the revolving credit facility.
Senior Subordinated Notes. In 1999, we sold $155.0 million of senior subordinated notes in a private placement with a final maturity of 2009 due in a single payment which were subsequently exchanged for registered publicly tradable notes under the same terms and conditions. The subordinated notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include limitations on debt incurrence, restricted payments, liens and sales of assets. The subordinated notes are unsecured and are guaranteed on a subordinated basis by our material subsidiaries. We incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes. The senior subordinated notes are callable at our option, in whole or in part, at 105% of par value beginning in June 2004 and are callable at decreasing premiums thereafter. Our ability to call these notes may be restricted by the covenants under our other debt facilities.
Covenant Compliance. We were in compliance with all covenants in our debt agreements at December 31, 2003.
Environmental
The construction and operation of our gathering systems, plants and other facilities used for the gathering, processing, treating or transporting of gas and NGLs are subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at our facilities or at facilities to which we send wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. We employ specialists in environmental engineering, safety and regulatory compliance to monitor environmental and safety compliance at our facilities. In addition, on an ongoing basis, our environmental engineers perform environmental assessments of our existing facilities. We believe that we are in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities. The costs for compliance with current environmental laws and regulations have not had and, we believe, will not have a material adverse effect on our financial position or results of operations.
Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In conducting this audit on the gathering systems we acquired in February 2003, we identified many well sites that include underground sump tanks, pits, or tinhorns that are not properly permitted according to Wyoming Oil and Gas Conservation Commission, or WYOGCC, regulations. We have reported these violations to WYOGCC and have provided our remediation plan to them. All of the underground facilities that were out of compliance have been removed and in addition, all but three of the sites have been completely remediated. These remaining three sites are currently under going remediation according to the plan approved by the WYOGCC. The seller of these assets established a $1.5 million escrow account to cover the costs of remediation. To date, actual expenditures have been less than $1.0 million, and we believe that total remediation costs will be less than the escrow amount.
The Texas Council on Environmental Quality, which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to it regarding a voluntary emissions reduction plan for the permitting of existing "grand-fathered" air emissions sources
within Texas. A "grand-fathered" air emissions source is one that does not need a state-operating permit because it was constructed prior to 1971. We operate a number of these sources within Texas, including portions of our Midkiff/Benedum, Gomez and Mitchell Puckett systems. In connection with a modernization program, which was completed in March 2003, we replaced the majority of our "grand-fathered" equipment in Texas. We believe that the potential cost of complying with these regulations for our remaining "grand-fathered" equipment will not have a material adverse effect on our results of operations or financial position.
We anticipate that the trend in environmental legislation and regulation will continue to be toward stricter standards. Federal regulations regarding spill prevention and containment have recently been modified to establish a lower threshold of storage capacity of petroleum and petroleum by-products at a site for which a spill prevention plan is required. We are evaluating all of our assets for compliance with this regulation and estimate that approximately 100 existing sites will need to be modified to meet the new requirements. We currently estimate our costs for compliance to be approximately $1.2 million. The new spill prevention plans must be in place for covered assets by August 2004. All modifications called for by those plans must be in place by February 2005.
We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $4.0 million for the year ended December 31, 2003, including approximately $736,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material adverse effect on our financial position or results of operations.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow and net income in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our marketing activities to protect profit margins. This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.
We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these goals. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.
We also use financial instruments to reduce basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.
We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and through OTC swaps and options with various counterparties, consisting primarily of investment banks, financial institutions and other natural gas companies. We conduct credit reviews of all of our OTC counterparties and have agreements with many of these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative OTC exposures. OTC exposure is marked-to-market daily for the credit review process. Our exposure to OTC credit risk is reduced by our ability to require a margin deposit from our counterparties based
upon the mark-to-market value of their net exposure. We are also subject to margin deposit requirements under these same agreements and under margin deposit requirements for our NYMEX transactions. At December 31, 2003, we had $5.7 million of margin deposits outstanding.
We continually monitor and review the credit exposure to our marketing counterparties. In order to minimize our credit exposures, we have utilized existing netting agreements to reduce our net credit exposure, established new netting agreements with additional customers, terminated several long-term marketing obligations, negotiated accelerated payment terms with several customers, and reduced the amount of credit which we make available to various customers. Although netting agreements similar to those that we utilize have been upheld by bankruptcy courts in the past, if any of these customers with whom we have netting agreements were to file for bankruptcy, we can provide no assurance that our agreements will not be challenged or as to the outcome of any challenge.
The use of financial instruments may expose us to the risk of financial loss in some circumstances, including instances when (i) our equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices.
Risk Policy and Control. We control the extent of risk management and marketing activities through policies and procedures that involve the senior level of management. On a daily basis, our marketing activities are audited and monitored by our independent risk oversight department, or IRO. This department reports to the Chief Financial Officer, thereby providing a separation of duties from the marketing department. Additionally, the IRO reports monthly to the Risk Management Committee, or RMC. This committee is comprised of corporate managers and officers and is responsible for developing the policies and guidelines that control the management and measurement of risk. The RMC is also responsible for setting risk limits including value-at-risk and dollar stop loss limits. Our board of directors approves the risk limit parameters and risk management policy.
Hedge Positions. As of January 31, 2004, we have hedged approximately 49% of our projected 2004 equity natural gas volumes and approximately 55% of our estimated equity production of crude oil, condensate, and NGLs. All of these contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Product purchases when the hedged transactions occur.
To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly correlated with changes in the price of the forecasted transaction being hedged so that our exposure to the risk of commodity price changes is reduced. To meet this requirement, we hedge the price of the commodity and, if applicable, the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. We utilize crude oil as a surrogate hedge for natural gasoline, butane and condensate. Our hedges are tested for effectiveness at inception and on a quarterly basis thereafter. We use regression analysis based on a five-year period of time for this test. Based on the results of the regression analysis, these hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the year ended December 31, 2003, we recognized a loss of $110,000 from the ineffective portions of our hedges.
Outstanding Equity Hedge Positions and the Associated Basis for 2004. The following table details our hedge positions as of January 31, 2004. In order to determine the hedged price to the particular operating region, deduct the basis differential from the NYMEX price. The prices for NGLs do not include the cost of the hedges of approximately $1.2 million. There is no associated cost for the natural gas hedges.
Account balances related to equity and transportation hedging transactions at December 31, 2003 were $1.7 million in Current assets from price risk management activities, $5.2 million in Current Liabilities from price risk management activities, ($1.3) million in Deferred income taxes payable, net, and a $2.3 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders' Equity. Based on prices as of December 31, 2003, approximately $2.3 million of losses in Accumulated other comprehensive income will be reclassified to earnings in 2004.
Value at Risk. We measure market risk in our natural gas and liquid marketing portfolios using value-at-risk, or VaR. We define VaR as a measure of the maximum expected loss over a given horizon under normal market conditions. VaR does not explicitly indicate potential realized losses. VaR does, however, implicitly indicate a firm's potential realized loss if market conditions were to remain constant or if the portfolio is liquidated within the specified time period. Our calculations are derived from Financial Engineering Association's VaR Works using the variance/co-variance method. We assume a one-day holding period with a 95% confidence level. There is a 95% (19 out of 20 business days) chance that the portfolio loss will be less than a specified amount if the entire portfolio were liquidated the next day. As of December 31, 2003, our VaR position for natural gas and NGL marketing portfolios was $385,000 and the average for all of 2003 was $496,000. This figure includes the risk related to our entire marketing portfolio of natural gas and NGL financial instruments and the related underlying physical transactions. We also measure market risk by sensitivity valuations. As of
December 31, 2003, an increase in natural gas prices of $1.00 per MMbtu would lead to an increase in the fair value of our marketing portfolio of $135,000 and an increase in crude oil prices of $5.00 per barrel would lead to an increase in the fair value of our marketing portfolio of $600,000. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods.
Summary of Derivative Positions. A summary of the change in our derivative position from December 31, 2002 to December 31, 2003 is as follows (dollars in thousands):
A summary of our outstanding derivative positions at December 31, 2003 is as follows (dollars in thousands):
(1)Other actively quoted prices are derived from broker quotations, trade publications, and industry indices.
(2)Other valuation methods are the Black-Scholes option-pricing model utilizing prices and volatility obtained from broker quotations, trade publications, and industry indices.
Foreign Currency Derivative Market Risk. As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage, and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 2003, the net notional value of such contracts was approximately $24.3 million in Canadian dollars, which approximates fair market value.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003:
Report of Management
Report of Independent Auditors
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Consolidated Statement of Operations
Consolidated Statement of Changes in Stockholders' Equity
Notes to Consolidated Financial Statements
REPORT OF MANAGEMENT
The financial statements and other financial information included in this Annual Report on Form 10-K are the responsibility of Management. The financial statements have been prepared in conformity with generally accepted accounting principles appropriate in the circumstances and include amounts that are based on Management's informed judgments and estimates.
Management relies on the Company's system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with Management's authorization. The concept of reasonable assurance is based on the recognition that there are inherent limitations in all systems of internal accounting control and that the cost of such systems should not exceed the benefits to be derived. The internal accounting controls, including internal audit, in place during the periods presented are considered adequate to provide such assurance.
PricewaterhouseCoopers LLP, independent auditors, audits the Company's financial statements. Their report states that they have conducted their audit in accordance with generally accepted auditing standards. Those standards require that the independent auditors consider internal control in planning and performing their audit, and to determine the nature, timing and extent of tests to be performed.
Oversight of Management's financial reporting and internal accounting control responsibilities is exercised by the board of directors, through an Audit Committee that consists solely of outside directors. The Audit Committee meets periodically with financial management, internal auditors and the independent auditors to review how each is carrying out its responsibilities and to discuss matters concerning auditing, internal accounting control and financial reporting. The independent auditors and the Company's internal audit department have free access to meet with the Audit Committee without Management present.
/s/ PETER A. DEA Peter A. Dea
Chief Executive Officer and President
/s/ WILLIAM J. KRYSIAK William J. Krysiak
Executive Vice President-Chief Financial Officer (Principal Financial and Accounting Officer)
REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and
Stockholders of Western Gas Resources, Inc.
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 4 to the financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. As discussed in Note 1 to the financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003 and its method of testing long-lived assets for impairment.
PricewaterhouseCoopers LLP
Denver, Colorado
March 9, 2004
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(000s, except share data)
The accompanying notes are an integral part of the consolidated financial statements.
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(000s)
The accompanying notes are an integral part of the consolidated financial statements.
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(000s, except share and per share amounts)
The accompanying notes are an integral part of the consolidated financial statements.
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(000s, except share amounts)
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (Continued)
(000s, except share amounts)
The accompanying notes are an integral part of the consolidated financial statements.
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-NATURE OF ORGANIZATION
Western Gas Resources, Inc. (the "Company") explores for, develops and produces, gathers, processes and treats, transports and markets natural gas and natural gas liquids ("NGLs"). In its upstream operations, the Company explores for, develops and produces natural gas reserves primarily in the Rocky Mountain region. In its midstream operations the Company designs, constructs, owns and operates natural gas gathering, processing and treating facilities and owns and operates regulated transportation facilities and offers marketing services in order to provide its customers with a broad range of services from the wellhead to the sales delivery point. The Company's midstream operations are conducted in major gas-producing basins in the Rocky Mountain, Mid-Continent and Southwestern regions of the United States.
The Company has completed three public offerings of Common Stock. In December 1989, the Company issued 3,527,500 shares of Common Stock at a public offering price of $11.50 per share. In November 1991, the Company issued 4,115,000 shares of Common Stock at a public offering price of $18.375 per share. In November 1996, the Company issued 6,325,000 shares of Common Stock at a public offering price of $16.25 per share.
The Company has also completed two public offerings of preferred stock. In November 1992, the Company issued 1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation preference of $25 per share, at a public offering price of $25 per share, redeemable at the Company's option on or after November 15, 1997. In 2000, the Company re-purchased 39,190 of the $2.28 Cumulative Preferred Stock for a total consideration of approximately $1.0 million. In 2001, the Company purchased in open market transactions an additional 5,100 shares of this preferred stock for a total cost, including broker commissions, of approximately $129,000, or an average of $25.29 per share of this preferred stock. In December 2001, the Company redeemed 808,864 shares of this preferred stock at the liquidation preference for total proceeds of $20.6 million including accrued and unpaid dividends. In December 2002, the Company redeemed the remaining 546,846 shares of this preferred stock at the liquidation preference for total proceeds of $14.0 million including accrued and unpaid dividends. This redemption was funded with amounts available under the Revolving Credit Facility.
In February 1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible Preferred Stocks with a liquidation preference of $50 per share, at a public offering price of $50 per share, redeemable at the Company's option on or after February 16, 1997 and convertible at the option of the holder into Common Stock at a per share price of $39.75. In November 2003 and in December 2003, the Company issued notices of redemption for approximately 700,000 and 800,000 shares, respectively, of its $2.625 cumulative convertible preferred stock at the liquidation preference plus 0.525% premium. In relation to the notice of redemption issued in November 2003, a total of 850,700 common shares were issued and $1.2 million was paid in cash to complete the redemption. In relation to the notice of redemption issued in December 2003, a total of 989,622 common shares were issued in January 2004, and $672,000 was paid in cash, also in January 2004, to complete the redemption.
In 2002, the Company adopted a Stockholder Rights Plan under which rights were distributed as a dividend at the rate of one right for each share of its common stock held by stockholders of record as of the close of business on April 9, 2002. Each right initially will entitle stockholders to buy one unit consisting of 1/100th of a share of a new series of preferred stock for $180 per unit. The right generally will be exercisable only if a person or group acquires beneficial ownership of 15% or more of the Company's then outstanding common stock or commences a tender or exchange offer upon
consummation of which a person or group would beneficially own 15% or more of its then outstanding common stock. The rights will expire on March 22, 2011.
Significant Projects and Asset Divestitures
Acquisition and Disposition of Gathering Systems. Effective February 1, 2003, the Company acquired several gathering systems in Wyoming, primarily located in the Green River Basin with smaller operations in the Powder River and Wind River Basins, for a total of $37.1 million. Several of the systems located in the Powder River did not integrate directly into the Company's existing systems, and accordingly these systems were sold. During the year ended December 31, 2003, the income, if any, generated by the assets sold was immaterial for separate presentation as a discontinued operation.
Acquisition of Sand Wash Properties. In August 2003, through the acquisition of the stock of a private corporation for $12.9 million, the Company acquired additional reserves, production and acreage in this area. The assets of this private entity consisted primarily of the remaining interests in various Sand Wash properties operated by the Company.
Toca Processing Facility. In September 2002, the Company sold its Toca processing facility in Louisiana. The sale price was $32.2 million and resulted in a pre-tax loss of approximately $230,000. During the year ended December 31, 2002, this facility generated net after-tax earnings of approximately $683,000, or $.02 per share of common stock, respectively. The Company believes the results from this facility are immaterial for separate presentation as a discontinued operation. Approximately $15.0 million of the proceeds received from this asset sale were initially used to reduce amounts outstanding on the Company's Revolving Credit Facility. At December 31, 2002, the remaining amount of $17.2 million was on deposit with a trustee in anticipation of the completion of a like-kind exchange transaction and was reflected on the Consolidated Balance Sheet under the caption Other current assets. These funds, along with additional amounts drawn on the Company's Revolving Credit Facility, were used in a February 2003 acquisition of several gathering systems described above.
Powder River Basin Coal Bed Methane. The Company continues to develop its Powder River Basin coal bed methane reserves and expand the associated gathering system in northeast Wyoming. During the years ended December 31, 2003, 2002 and 2001, the Company expended approximately $53.3 million, $71.0 million and $82.1 million, respectively, on this project.
Greater Green River Basin. The Company's assets in southwest Wyoming include the Granger and Lincoln Road facilities (collectively the "Granger Complex"), its 50% equity interest in Rendezvous Gas Services, L.L.C. ("Rendezvous"), the Red Desert facility, Wamsutter gathering and production from the Jonah Field, Pinedale Anticline and Sand Wash areas. During the years ended December 31, 2003, 2002 and 2001, the Company expended approximately $102.5 million, $37.1 million and $28.6 million, respectively, in this area.
Pinnacle Gas Treating, Inc. In December 2000, the Company signed an agreement for the sale of the stock of the Company's wholly owned subsidiary Pinnacle Gas Treating, Inc. for approximately $38.0 million. The sale closed in January 2001 and resulted in an approximate pre-tax gain for financial reporting purposes of $12.1 million in the first quarter of 2001.
NOTE 2-SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies followed by the Company and its wholly owned subsidiaries are presented here to assist the reader in evaluating the financial information contained herein. The Company's accounting policies are in accordance with generally accepted accounting principles.
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and the Company's wholly owned subsidiaries. All material inter-company transactions have been eliminated in consolidation. The Company's interest in certain non-controlled investments is accounted for by the equity method.
Inventories. The cost of gas and NGL inventories are determined by the weighted average cost method on a location-by-location basis. Residue and NGL inventory covered by derivative contracts is accounted for on a specific identification basis. Product inventory includes $67.1 million and $42.1 million of gas and $1.6 million and $1.4 million of NGLs at December 31, 2003 and 2002, respectively.
Property and Equipment. Property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets. Repair and maintenance of property and equipment is expensed as incurred.
Depreciation is provided using the straight-line method based on the estimated useful life of each facility, which ranges from three to 35 years. Useful lives are determined based on the shorter of the life of the equipment or the reserves serviced by the equipment. The cost of acquired gas purchase contracts is amortized using the straight-line method or units of production.
In connection with the adoption of SFAS No. 143 on January 1, 2003, a review was completed of the Company's operating assets. As a result of this review, the operating lives and salvage values of the associated equipment was reevaluated. As a result of this evaluation, the Company extended the useful life of many of its operating assets and adjusted the estimated salvage value of its operating equipment. These adjustments resulted in an approximate $10.7 million, or $0.20 per share of common stock-assuming dilution, decrease in depreciation, depletion and amortization in the year ended December 31, 2003, from the expense calculated using the previous useful lives. The adjustments to the salvage value and depreciable lives of the Company's assets are treated as a revision of an estimate and are accounted for on a prospective basis.
Oil and Gas Properties and Equipment. The Company follows the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved developed reserves.
Income Taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined and accounted for in accordance with SFAS No. 109, "Accounting for Income Taxes."
Foreign Currency Adjustments. The Company has a subsidiary in Canada. The functional currency of this subsidiary is the Canadian dollar. The assets and liabilities associated with this subsidiary are
translated into U.S. dollars at the exchange rate as of the balance sheet date and revenues and expenses at the weighted-average of exchange rates in effect during each reporting period. The translation gains (losses) for the years ended December 31, 2003, 2002 and 2001 were $1.2 million, $283,000 and $(440,000), respectively, net of tax.
Revenue Recognition. In the Gas Gathering, Processing and Treating segment, the Company recognizes revenue for its services at the time the service is performed. The Company records revenue from its gas and NGL marketing activities, including sales of the Company's equity production, upon transfer of title. Gas imbalances on the Company's production are accounted for using the sales method. For its marketing activities the Company utilizes mark-to-market accounting. Under mark-to-market accounting, the expected margin to be realized over the term of the transaction is recorded in the month of origination. To the extent that a transaction is not fully hedged or there is any hedge ineffectiveness, additional gains or losses associated with the transaction may be reported in future periods. In the Transportation segment, the Company realizes revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. See additional discussion in Note 9-Business Segments and Related Information.
Accounting for Derivative Instruments and Hedging Activities. In June 1998, the Financial Accounting Standards Board, (the "FASB"), issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, which was subsequently amended by SFAS No.138 and SFAS No. 149, the Company is required to recognize the change in the market value of all derivatives, including storage contracts and firm transportation to the extent utilized, as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. Upon adoption of SFAS No. 133 and mark-to-market accounting on January 1, 2001, the impact was a decrease in a component of stockholders' equity through Accumulated other comprehensive income of $22.5 million, an increase to Current assets of $52.6 million, an increase to Current liabilities of $86.9 million, an increase in Other long-term liabilities of $1.1 million and a decrease in Deferred income taxes payable of $12.9 million.
Of the $22.5 million decrease to Accumulated other comprehensive income resulting from the January 1, 2001 adoption of SFAS No. 133, $22.0 million was reversed during the year ended December 31, 2001 with gains and losses from the underlying transactions recognized through operating income. The remaining $500,000 of this transition entry was recognized through operating income during 2002. The non-cash impact to the Company's results of operations in the year ended December 31, 2001 resulting from the adoption of mark-to-market accounting for its marketing activities resulted in additional pre-tax income of $19.9 million.
Comprehensive Income. Accumulated other comprehensive income (loss) is reported as a separate component of stockholders' equity. Accumulated other comprehensive income (loss) includes cumulative translation adjustments for foreign currency transactions and the change in fair market value of cash flow hedges. The Company's accumulated derivative losses at December 31, 2003 total $2.3 million and will be reclassified into earnings during 2004. These items are separately reported on the Consolidated Statement of Changes in Stockholders' Equity.
Impairment of Long-Lived Assets. SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" required that long-lived assets be reviewed
whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Effective for the Company's year ended December 31, 2002, SFAS No. 121 was superceded by SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 144 also requires that long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable and that assets are to be evaluated at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets. In order to determine whether an impairment exists, the Company compares its net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset.
The Company reviews its assets at the plant facility, the related group of plant facilities or the oil and gas producing field or producing coal seam level. Prior to 2003, the Company completed its impairment analysis on its oil and gas producing properties on an individual well-by-well basis. In the fourth quarter of 2003, the Company conducted a review of its oil and gas producing properties, which included an evaluation of the geologic formations and production history for the Company's producing properties. This review indicated that the cash flows from individual wells in its operating areas were not largely independent of the cash flows of other wells producing in the same field or coal seam. As a result of this review, the Company redefined the asset groupings to a field wide analysis for impairment for the Jonah, Pinedale and Sand Wash Basins and a grouping of all wells drilled into related coal seams for the Powder River Basin. These asset groupings were used to determine if any impairment was necessary for the year ended December 31, 2003 and it was determined that none of the asset groups were impaired. In addition, while the Company did not recognize any impairment of its producing properties in the years ended December 31, 2002 or 2001 under the asset groupings utilized in those years, a reevaluation of those years using the new asset groups also did not result in an impairment of its producing properties.
Cumulative Effect of a Change in Accounting Principle. In June 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations." SFAS No. 143 was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of a liability for an asset retirement obligation and the associated asset retirement cost. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a $11.5 million increase to Property and equipment, a $4.4 million increase to Accumulated depreciation, depletion and amortization, a $17.8 million increase to Other long-term liabilities and a $6.7 million non-cash, after-tax loss from the Cumulative effect of a change in accounting principle.
The following is a reconciliation of the asset retirement obligation for the year ended December 31, 2003 (000's):
Exclusive of assets disposed of during 2002, if the Company had adopted SFAS No. 143 as of January 1, 2002, it estimates that the asset retirement obligation at that date would have been $15.7 million, based on the same assumptions used in its calculation of the obligation at January 1, 2003. The estimated 2002 pro forma effect of a hypothetical January 1, 2002 adoption of SFAS No. 143 on net income and earnings per share, for annual and interim periods, is not material.
Earnings Per Share of Common Stock. The Company follows SFAS No. 128, "Earnings per Share", which requires that earnings per share and earnings per share-assuming dilution be calculated and presented on the Consolidated Statement of Operations. In accordance with SFAS No. 128, earnings per share of common stock are computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings per share of common stock-assuming dilution is computed by dividing income attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income attributable to common stock is income less preferred stock dividends. The Company declared preferred stock dividends of $6.8 million, $8.2 million and $11.2 million for each of the years ended December 31, 2003, 2002 and 2001, respectively. Common stock options and the $2.625 cumulative convertible preferred stock are potential common shares. The following is a reconciliation of the weighted average shares of common stock outstanding to the weighted average common shares outstanding-assuming dilution.
The numerators and the denominators for these periods were adjusted to reflect these potential shares, conversion of the $2.625 cumulative convertible preferred stock and any related preferred dividends in calculating fully diluted earnings per share.
Concentration of Credit Risk. Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable and over-the-counter ("OTC") swaps and options. The risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations.
The Company continually monitors and reviews the credit exposure to its marketing counter parties. This review has resulted in a reduction in sales volumes with various counter parties in order to maintain acceptable credit exposures. During 2002 and 2001, the Company reserved approximately $1.6 million and $2.7 million for doubtful accounts through a charge to Selling and administrative expense. During 2003, the Company did not increase its reserve for doubtful accounts. The Company records a reserve for doubtful accounts on a specific identification basis, and the balance in the reserve for doubtful accounts was $2.3 million and $3.9 million, respectively, at December 31, 2003 and 2002.
Cash and Cash Equivalents. Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.
Supplementary Cash Flow Information. Interest paid was $28.0 million, $28.1 million, and $30.2 million, respectively, for the years ended December 31, 2003, 2002 and 2001. Capitalized interest associated with construction of new projects was $1.8 million, $1.7 million, and $4.7 million, respectively, for the years ended December 31, 2003, 2002 and 2001. Income taxes paid were $11.1 million, $1.5 million, and $18.7 million, respectively, for the years ended December 31, 2003, 2002 and 2001.
Stock Compensation. As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation", the Company has elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." The Company has complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. The Company realizes an income tax benefit from the exercise of non-qualified stock options related to the difference between the market price at the date of exercise and the option price. This difference is credited to additional paid-in capital.
The Company is required to record compensation expense (if not previously accrued) equal to the number of unexercised re-priced options multiplied by the amount by which its stock price at the end of any quarter exceeds $21 per share. The Company had options covering 24,719, 59,500, and 118,028 common shares outstanding at December 31, 2003, 2002 and 2001, respectively, which were treated as re-priced options. Based on the Company's stock price at December 31, 2003, 2002 and 2001 of $47.25, $36.85, and $32.32 per share, respectively; expense of $529,000, $224,000 and income of $170,000 was recorded in the years ended December 31, 2003, 2002, and 2001, respectively.
SFAS No. 123 encourages companies to record compensation expense for stock-based compensation plans at fair value. As permitted under SFAS No. 123, the Company has elected to continue to measure compensation costs for such plans as prescribed by APB No. 25. Such information was only calculated for the options granted under the 1999 Stock Option Plan, the Chief Executive Officer's Plan, the 2002 Stock Option Plan and the 2002 Directors' Plan, as there were no grants under any other plans.
The following is a summary of the options to purchase the Company's common stock granted during the years ended December 31, 2003, 2002 and 2001, respectively.
The following is a summary of the weighted average fair value per share of the options granted during the years ended December 31, 2003, 2002, and 2001, respectively.
These values were estimated using the Black-Scholes option-pricing model with the following assumptions:
Had compensation expense for the Company's 2003, 2002 and 2001 grants for stock-based compensation plans been determined consistent with the fair value method under SFAS No. 123, the Company's net income, income attributable to common stock, earnings per share of common stock and earnings per share of common stock-assuming dilution would approximate the pro forma amounts below (000s, except per share amounts):
The fair market value of the options at grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense.
Use of Estimates and Significant Risks. The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported for assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the amounts reported for revenues and expenses during the reporting period. Therefore, the reported amounts of the Company's assets and liabilities, revenues and expenses and associated disclosures with respect to contingent assets and obligations are necessarily affected by these estimates. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with experts and other methods considered reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the estimates used. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
The Company is subject to a number of risks inherent in the industry in which it operates, including price volatility, counterparty credit risk, the success of its drilling programs and other gas supply. The Company's financial condition and results of operations will depend significantly upon the prices received for gas and NGLs. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the Company must continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within the Company's control.
Recently Issued Accounting Pronouncements.
SFAS No. 141 and SFAS No. 142. SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Intangible Assets" were issued in June 2001 and became effective for the Company on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Consolidated Balance Sheet. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangibles would be included in the Notes to Consolidated Financial Statements. Historically, the Company has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the Oil and gas properties and equipment, even after SFAS No. 141 and No.142 became effective.
This interpretation of SFAS No. 141 and No. 142 described above would only affect the Consolidated Balance Sheet classification of oil and gas leaseholds. The Company's results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies".
At December 31, 2003, the Company had undeveloped leaseholds of $55.9 million that would be classified on the Consolidated Balance Sheet as "intangible undeveloped leaseholds" and developed leaseholds of $31.7 million that would be classified as "intangible developed leaseholds" if the interpretation currently being considered was applied. The Company will continue to classify its oil and
gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
FIN 46. In January 2003, the FASB issued Interpretation No. 46, or "FIN 46", "Consolidation of Variable Interest Entities." FIN 46 provides guidance on how to identify a variable interest entity, or VIE, and determine when the assets, liabilities, and results of operations of a VIE need to be included in a company's consolidated financial statements. FIN 46 also requires additional disclosures by primary beneficiaries and other significant variable interest holders in a VIE. The provisions of FIN 46 are effective immediately for all VIEs created after January 31, 2003. For VIEs created before February 1, 2003, the provisions of FIN 46, as amended, must be adopted at the beginning of the first quarter of 2004. The Company did not create any VIEs after January 31, 2003 and it is continuing to evaluate the impact of FIN 46 on any VIEs created prior to that date and will adopt this pronouncement as required.
Reclassifications. Certain prior years' amounts in the consolidated financial statements and related notes have been reclassified to conform to the presentation used in 2003.
NOTE 3-RELATED PARTIES
From time to time, the Company enters into joint ventures and partnerships in order to reduce risk, create strategic alliances and to establish itself in oil and gas producing basins in the United States. All transactions entered into by the Company with its related parties were consummated in the ordinary course of business and on terms that would be comparable to those obtained from third parties.
Fort Union. In 1998, the Company joined with other industry participants to form Fort Union Gas Gathering, L.L.C. ("Fort Union"), to construct a gathering pipeline and treater in the Powder River Basin in northeast Wyoming. At December 31, 2003 and 2002, the Company owned an approximate 13% interest in Fort Union and is the construction manager and field operator. The Company accounts for its investment in this entity under the equity method of accounting. Construction and expansions of the gathering header and treating system were project financed by Fort Union. At December 31, 2003, Fort Union had total project financing debt outstanding of $41.7 million. This debt is amortizing on an annual basis and is scheduled to be fully paid in 2009. All participants in Fort Union have guaranteed Fort Union's payment of the project financing on a proportional basis, resulting in the Company's guarantee of $5.5 million of the debt of Fort Union. This guarantee is not reflected on the Consolidated Balance Sheet.
The Company has entered into long-term agreements for firm gathering services on 83 MMcf per day of capacity for $0.14 per Mcf on Fort Union. The Company acts as field operator of Fort Union and charges a monthly overhead fee to cover such services. In 2003, 2002 and 2001, the Company received overhead fees from Fort Union totaling $(2,000), $25,000 and $483,000, respectively, and the Company paid to Fort Union a total of $6.4 million, $5.3 million and $3.3 million for gathering services, respectively. At December 31, 2003 and 2002, the Company had a net amount due to Fort Union of $71,000 and $258,000, respectively. At December 31, 2003, the Company's investment in Fort Union totaled $3.3 million and is included in Other assets on the Consolidated Balance Sheet.
Rendezvous. At December 31, 2003 and 2002, the Company owned a 50% interest in Rendezvous Gas Services, L.L.C. ("Rendezvous"), and the Company serves as field operator of its systems. Rendezvous was formed in 2001 to gather gas for the Company and other third parties along the Pinedale Anticline for blending or processing at either the Company's Granger Complex or at a third-
party owned processing facility. Rendezvous was expanded during 2003 and 2002, and at December 31, 2003, the Company had a total of $36.0 million invested in this venture. The investment is included in Other assets on the Consolidated Balance Sheet. The Company accounts for its investment in this entity under the equity method of accounting. The Company charges a monthly overhead fee to act as field operator of Rendezvous and an overhead charge for capital projects it constructs on behalf of the venture. In 2003 and 2002, the Company received overhead fees as field operator from Rendezvous totaling $100,000 in each year and overhead fees on capital projects totaling $825,000 and $352,000, respectively. In 2003 and 2002, the Company paid to Rendezvous a total of $4.7 million and $2.2 million, respectively, for gathering services. At December 31, 2003 and 2002, the Company had a net amount due to Rendezvous of $382,000 and $3.6 million, respectively.
Officer Transactions. In prior years, the Company had entered into agreements committing the Company to loan to certain key employees an amount sufficient to exercise their options as each portion of their options vests under the Key Employees' Incentive Stock Option Plan. The loan and accrued interest were to be forgiven if the employee was continually employed by the Company and upon a resolution of the board of directors. In 2002, the Company forgave loans related to 62,500 shares of Common Stock totaling $703,000. Pursuant to the terms of an agreement entered into in 2001, the remaining loan was forgiven in May 2003. As of December 31, 2003, there were no loans outstanding under these programs and the program is no longer in effect. At December 31, 2002, loans related to 27,500 shares of Common Stock totaling $295,000 were outstanding under these programs. In prior years, the Company had accrued for the forgiveness of these loans.
In October 2001, the Company's former Chief Executive Officer and President retired. The Company had entered into a consulting agreement with this executive providing for payments of $167,000 in May 2002 and $175,000 in May 2003.
NOTE 4-COMMODITY RISK MANAGEMENT
Risk Management Activities. The Company's commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of the Company's equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by the Company's operating budget. The second goal is to manage price risk related to the Company's physical gas, crude oil and NGL marketing activities to protect profit margins. This risk relates to fixed price purchase and sale commitments, the value of storage inventories and exposure to physical market price volatility.
The Company utilizes a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter market ("OTC") to accomplish these objectives. These instruments allow the Company to preserve value and protect margins because corresponding losses or gains in the value of the financial instruments offset gains or losses in the physical market.
The Company also uses financial instruments to reduce basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations.
The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and through OTC swaps and options with various counter parties, consisting primarily of financial institutions and other natural gas companies. The Company conducts a credit review of OTC counter parties and has agreements with many of these parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative OTC exposures. OTC exposure is marked-to-market daily for the credit review process. The Company's exposure to OTC credit risk is reduced by its ability to require a margin deposit from its counterparties based upon the mark-to-market value of their net exposure. The Company is also subject to margin deposit requirements under these same agreements and under margin deposit requirements for its NYMEX transactions. At December 31, 2003 and 2002, the Company had posted margin deposits totaling $5.7 million and $19.6 million, respectively, with various counterparties.
The use of financial instruments may expose the Company to the risk of financial loss in certain circumstances, including instances when (i) the Company's equity volumes are less than expected, (ii) the Company's customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) the Company's OTC counter parties fail to perform. To the extent that the Company engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, it is similarly insulated against decreases in such prices.
All equity hedging contracts are designated and accounted for as cash flow hedges. As such, gains and losses related to the effective portions of the changes in the fair value of the derivatives are recorded in Accumulated other comprehensive income, a component of Stockholders' equity. Realized gains or losses on these cash flow hedges are recognized in the Consolidated Statement of Operations through Sale of gas or Sale of natural gas liquids when the hedged transactions occur. Realized and unrealized gains or losses represented by the periodic or final cash settlements from economic hedges are included in Price risk management activities on the Consolidated Statement of Operations. Economic hedges are financially settled derivatives that either were not designated or did not qualify as hedges under SFAS No. 133.
To qualify as cash flow hedges, the hedge instruments must be designated as cash flow hedges and changes in their fair value must be highly correlated with changes in the price of the forecasted transaction being hedged so that the Company's exposure to the risk of commodity price changes is reduced. To meet this requirement, the Company hedges the price of the commodity, and if applicable, the basis between that derivative's contract delivery location and the cash market location used for the actual sale of the product. This structure attains a high level of effectiveness, insuring that a change in the price of the forecasted transaction will result in an equal and opposite change in the cash price of the hedged commodity. The Company utilizes crude oil as a surrogate hedge for natural gasoline, butane and condensate. The Company's hedges are tested for effectiveness at inception and on a quarterly basis thereafter. Regression analysis based on a five-year period of time is used for this test. Based on the results of the regression analysis, these hedges are expected to continue to be "highly effective" under SFAS No. 133 in the future. Gains or losses from the ineffective portions of changes in the fair value of cash flow hedges are recognized currently in earnings through Price risk management activities. During the year ended December 31, 2003 and 2002, the Company recognized losses of $110,000 and $154,000, respectively, from the ineffective portions of its hedges.
In 2003, in order to properly align the Company's hedged volumes of natural gas to its forecasted equity production, the Company discontinued hedge treatment on financial instruments for 10 MMcf per day of natural gas and 50,000 Barrels per month of ethane. As a result, a pre-tax loss of $2.8 million was reclassified into earnings from Accumulated other comprehensive income. In 2002, in order to properly align the Company's hedged volumes of natural gas to its forecasted equity
production for 2003, the Company discontinued hedge treatment on financial instruments for 6 MMcf per day. As a result, a pre-tax gain of $790,000 was reclassified into earnings in 2002 from Accumulated other comprehensive income. There were no gains or losses reclassified into earnings as a result of the discontinuance of cash flow hedges in 2001.
Account balances related to equity hedging transactions at December 31, 2003 were $1.7 million in Current Assets from price risk management activities, $5.2 million in Current Liabilities from price risk management activities, ($1.3) million in Deferred income taxes payable, net, and a $2.3 million after-tax unrealized loss in Accumulated other comprehensive income, a component of Stockholders' Equity. Based on the commodity prices as of December 31, 2003, the after-tax loss of $2.3 million will be re-classified from Accumulated other comprehensive income to Product purchases during the next twelve months.
Natural Gas Derivative Market Risk. As of December 31, 2003, the Company held a notional quantity of approximately 268 Bcf of natural gas futures, swaps and options extending from January 2004 to October 2006 with a weighted average duration of approximately five months. This was comprised of approximately 107 Bcf of long positions and 161 Bcf of short positions in these instruments. As of December 31, 2002, the Company held a notional quantity of approximately 303 Bcf of natural gas futures, swaps and options extending from January 2003 to October 2006 with a weighted average duration of approximately six months. This was comprised of approximately 116 Bcf of long positions and 87 Bcf of short positions in these instruments.
Crude Oil and NGL Derivative Market Risk. As of December 31, 2003, the Company held a notional quantity of approximately 191,520 MGal of NGL futures, swaps and options extending from January 2004 to December 2004 with a weighted average duration of approximately six months. This was comprised of approximately 120,960 MGal of long positions and 70,560 MGal of short positions in these instruments. As of December 31, 2002, the Company held a notional quantity of approximately 275,940 MGal of NGL futures, swaps and options extending from January 2003 to December 2003 with a weighted average duration of approximately six months. This was comprised of approximately 138,600 MGal of long positions and 137,340 MGal of short positions in these instruments.
As of December 31, 2003, the Company did not hold any NGL futures, swaps or options for settlement beyond 2004. As of December 31, 2003, the estimated fair value of the aforementioned crude oil and NGL options held by the Company was approximately $(4.2) million.
Foreign Currency Derivative Market Risk. As a normal part of its business, the Company enters into physical gas transactions which are payable in Canadian dollars. The Company enters into forward purchases and sales of Canadian dollars from time to time to fix the cost of its future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 2003, the net notional value of such contracts was approximately $24.3 million in Canadian dollars, which approximated fair market value. As of December 31, 2002, the net notional value of such contracts was approximately $14.4 million in Canadian dollars, which again approximated its fair market value.
NOTE 5-DEBT
The following summarizes the Company's consolidated debt at the dates indicated (000s):
Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $300 million, which matures on April 24, 2007. At December 31, 2003, $94.0 million was outstanding under this facility. Loans made under this facility are secured by a pledge of the capital stock of the Company's significant subsidiaries. These subsidiaries also guarantee the borrowings under the facility. The Revolving Credit Facility contains a provision that requires the Company to secure loans under the facility with 75% of its oil and gas reserves. This provision would only be triggered in the event of a reduction to a debt rating on the Revolving Credit Facility of Ba3 or lower by Moody's Investors Service, Inc. (or "Moody's") or the reduction to a debt rating on the revolving credit facility of BB- or lower by Standard & Poor's Rating Services, a division of The McGraw-Hill Companies, Inc. (or "S&P"). This facility has been rated Ba1 by Moody's and BB+ by S&P.
The borrowings under the Revolving Credit Facility bear interest at Eurodollar rates or a base rate, as selected by the Company, plus an applicable percentage based on its debt to capitalization ratio. The base rate is the agent's published prime rate. The Company also pays a quarterly facility fee ranging between 0.30% and 0.50%, depending on its debt to capitalization ratio. This fee is paid on the total commitment. At December 31, 2003, the interest rate payable on borrowings under this facility was approximately 2.9%.
Under the Revolving Credit Facility, the Company is subject to a number of covenants, including: maintaining a total debt to capitalization ratio of not more than 55%; maintaining a senior debt to capitalization ratio of not more than 40%; and maintaining a ratio of EBITDA, as defined in the credit facility, to interest and dividends on preferred stock over the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005.
The credit facility ranks equally with borrowings under the Master Shelf Agreement with The Prudential Insurance Company.
Master Shelf Agreement. In December 1991, the Company entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 2003 are as indicated in the following table (000s):
The Company's borrowings under the Master Shelf Agreement are secured by a pledge of the capital stock of its significant subsidiaries, some of which have also provided a guaranty of payments owed by it under the facility. The Master Shelf Agreement requires the Company to secure loans under the facility with 75% of its oil and gas reserves. This provision would only be triggered in the event of a reduction to the debt rating on the Revolving Credit Facility of Ba3 or lower by Moody's or the reduction to the debt rating on the revolving credit facility of BB- or lower by S&P.
Under the Master Shelf Agreement, the Company is subject to a number of covenants, including: maintaining a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999; maintaining a total debt to capitalization ratio of not more than 55% and a senior debt to capitalization ratio of not more than 40%; maintaining a quarterly test of EBITDA, as defined in the Master Shelf Agreement, to interest for the last four quarters in excess of 3.25 to 1.0, increasing to 3.75 to 1.0 at March 31, 2004 and to 4.25 to 1.0 at March 31, 2005; and maintaining a ratio of senior debt to EBITDA of no greater than 4.0 to 1.0.
In the fourth quarter of 2003, the Company utilized funds available under the Revolving Credit Facility to fund $33.3 million in scheduled payments under the Master Shelf Agreement. During 2004, the Company is required to make scheduled payments totaling $35.0 million on this facility. The Company intends to fund these repayments with funds available under the Revolving Credit Facility.
Senior Subordinated Notes. At December 31, 2003, the Company had outstanding $155.0 million of Senior Subordinated Notes due in a single payment in 2009. The Senior Subordinated Notes bear interest at 10% per annum and were priced at 99.225% to yield 10.125%. These notes contain covenants, which include certain limitations on debt incurrence, restricted payments, liens and sales of assets. Under the calculation limiting restricted payments, including common dividends, approximately $76.8 million was available at December 31, 2003. The subordinated notes are unsecured and are guaranteed on a subordinated basis by the Company's material subsidiaries. The Company incurred approximately $5.0 million in offering commissions and expenses, which were capitalized and are being amortized over the term of the notes. The senior subordinated notes are callable at the Company's option, in whole or in part, at 105% of par value beginning in June 2004 and are callable at decreasing premiums thereafter.
Covenant Compliance. The Company is in compliance with all covenants in its debt agreements for each of the years ended December 31, 2003, 2002 and 2001.
Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2003 (000s):
NOTE 6-FINANCIAL INSTRUMENTS
The Company using available market information and valuation methodologies has determined the estimated fair values of the Company's financial instruments. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments.
The Company in estimating the fair value of its financial instruments used the following methods and assumptions:
Cash and cash equivalents, trade accounts receivable and accounts payable. Due to the short-term nature of these instruments, the carrying value approximates the fair value.
Long-term debt. The Company's long-term debt was comprised of fixed and floating rate facilities. The fair market value for the fixed rate debt was estimated using discounted cash flows based upon the Company's current borrowing rates for debt with similar maturities. The floating rate portion of the long-term debt was borrowed on a revolving basis, which accrues interest at current rates; as a result, carrying value approximates fair value of this outstanding debt.
Derivative contracts. Fair value represents the amount at which the instrument could be exchanged in a current arms-length transaction.
NOTE 7-INCOME TAXES
The provision for income taxes for the years ended December 31, 2003, 2002 and 2001, is comprised of (000s):
Not included in the above is the tax benefit allocated to the cumulative effect of a change in accounting principle of approximately $4.0 million for the year ended December 31, 2003. There were no such items in 2002 or 2001.
Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 2003 and 2002, net of the tax effect of the cumulative change in accounting principle, are as follows (000s):
The change in the net deferred income taxes in 2003 and 2002 includes a $700,000 and $1.2 million tax benefit, respectively, associated with the exercise of incentive stock options.
The differences between the provision for income taxes at the statutory rate and the actual provision for income taxes, before the tax effect of the change in accounting principle, for the years ended December 31, 2003, 2002 and 2001 are summarized as follows (000s):
At December 31, 2003, the Company had NOL carry-forwards for federal and state income tax purposes and AMT credit carry-forwards for federal income tax purposes of approximately $16.6 million and $50.2 million, respectively. These carry-forwards expire as follows (000s):
The Company believes that the NOL carry-forwards and AMT credit carry-forwards will be utilized prior to their expiration because they are substantially offset by existing taxable temporary differences reversing within the carry-forward period or are expected to be realized by achieving future profitable
operations based on the Company's dedicated and owned reserves, past earnings history and projections of future earnings.
NOTE 8-COMMITMENTS AND CONTINGENT LIABILITIES
Litigation.
Western Gas Resources, Inc. and Lance Oil & Gas Company, Inc. v. Williams Production RMT Company, (Defendant), Civil Action No. CO2-10-394, District Court, County of Sheridan, Wyoming. On October 23, 2002, the Company filed a complaint for declaratory relief and damages related to a dispute arising under a development agreement and other agreements between the parties. On October 24, 2003, the Company reached an agreement with the Defendant to settle these disputes. Under the terms of the settlement agreement, the Defendant and the Company each operate the drilling and production on approximately half of the jointly owned leasehold in the coal-bed methane development of the Powder River Basin of Wyoming. Effective November 1, 2003, the parties have agreed to an expanded area of mutual interest and the Company assumed an expanded area of dedication in its gas gathering operations in the Powder River Basin. The parties have also agreed to modifications to the gas gathering fee schedule. On November 3, 2003, the Company filed, in conjunction with the Defendant, a joint stipulation of voluntary dismissal of this action.
United States of America and ex rel. Jack J. Grynberg v. Western Gas Resources, Inc., et al., United States District Court, District of Colorado, Civil Action No. 97-D-1427. The Company is a defendant in litigation filed on June 30, 1997, along with over 300 natural gas companies in 72 separate actions filed by Mr. Grynberg on behalf of the federal government. The allegations made by Mr. Grynberg are that established gas measurement and royalty calculation practices improperly deprived the federal government of appropriate natural gas royalties and violate 31 U. S. C. 3729 (a) (7) of the False Claims Act. The cases have been consolidated to the United States District Court for the District of Wyoming. Discovery on the jurisdictional issues is being completed to determine if this matter qualifies as a qui tam (or class) action. On October 9, 2002, the court dismissed Mr. Grynberg's valuation claims, and his appeal against this decision was also unsuccessful. The Company believes that Mr. Grynberg's remaining claims are baseless and without merit and intends to vigorously contest the allegations in this case. At this time, the Company is unable to predict the outcome of this matter.
Price, et al. v. Gas Pipelines, Western Gas Resources, Inc., et al., District Court, Stevens County, Kansas, Case No. 99-C-30.The Company is a defendant in litigation filed on September 23, 1999, along with numerous other natural gas companies, in which Mr. Price is claiming an under measurement of gas and Btu volumes throughout the country. The Company along with other natural gas companies filed a motion to dismiss for failure to state a claim. The court denied these motions to dismiss. The court denied plaintiff's motion for certification as a class and, in the second quarter of 2003, the plaintiff amended and refiled for certification as a class. On May 12, 2003, Mr. Price filed a further claim, Will Price et al v. Western Gas Resources, Inc. et al., District Court, Stevens County, Kansas, Case No. 03C23, relating to certain matters previously removed from the foregoing action. The Company believes that Mr. Price's claims are without merit and intends to vigorously contest the allegations in this case. At this time, the Company is unable to predict the outcome of this matter.
In the Matter of the Appeal of Lance Oil & Gas Company from a Decision by the Department of Revenue, Docket No. 2003-44, Before the State Board of Equalization for the State of Wyoming. The Wyoming Department of Revenue has conducted an audit of the Company's wholly-owned subsidiary Lance Oil & Gas Company, Inc. for the period from January 1, 1998 through December 31, 1999. On March 24, 2003, the Department of Revenue notified the Company that it had assessed additional
severance taxes and increased taxable value for ad valorem tax purposes. The additional severance and ad valorem taxes claimed by the Department of Revenue amount to $196,000 and $351,000, respectively, together with statutory interest. The Company believes that the Wyoming Department of Revenue claims are without merit and intends to vigorously contest their assessments. On April 23, 2003, the Company filed a Notice of Appeal with the Wyoming State Board of Equalization. The hearing has been rescheduled to April 22, 2004. In the event that the Department of Revenue is successful in its argument, the Company's severance and ad valorem taxes will be affected in future years following the 1999 assessment. Although the amounts subject to the audit are immaterial, due to increasing production volumes in subsequent years, any such assessment could be material. At this time, the Company is unable to predict the outcome of this matter.
In the Matter of the Notice of Violation Issued to Mountain Gas Resources, Inc., Department of Environmental Quality, State of Wyoming. The Company's wholly-owned subsidiary received a Notice of Violation issued by the State of Wyoming Department of Environmental Quality for failing to obtain a permit prior to constructing certain dehydration units at facilities in Sublette County, Wyoming. This Notice of Violation was received after the Company self-reported to the Department of Environmental Quality in April 2003 that it had inadvertently failed to submit notices of intent and air permit applications for such dehydration units. The Company settled this matter in the fourth quarter of 2003 for an immaterial amount.
National Pipeline Mapping System. The Company received correspondence from the U.S. Department of Transportation regarding its failure to submit information for incorporation into the National Pipeline Mapping System within nine months of enactment of the Pipeline Safety Improvement Act of 2002. During the fourth quarter of 2003, the Company supplied all required information to the U.S. Department of Transportation Office of Pipeline Safety.
Price Reporting to Gas Trade Publications. In the third quarter of 2003, the Company learned that several employees in its marketing department furnished inaccurate information regarding natural gas transactions to energy publications, which compile and report energy index prices. The Company discovered the inaccuracies during a review of its marketing activities, which is being conducted in response to a subpoena issued by the Commodity Futures Trading Commission (or "CFTC"). These employees have identified inaccuracies associated with reporting of natural gas transactions primarily related to points in Texas. The Company's review of this and other regions is continuing as it responds to the CFTC subpoena. The Company is unable to predict the amount of fines or penalties to be assessed by the CFTC.
Other Litigation. The Company is involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of the Company's management, any liabilities that may result from these claims will not, individually or in the aggregate, have a material adverse effect on the Company's financial position, results of operations or cash flow.
Retirement Plan. The Company provides a Retirement Plan for its present and past employees, or participants. The purpose of the Retirement Plan is to provide a method for the participants to save towards their retirement. Beginning in January 1989, the participants were given the option to invest their contributions in the Western Gas Fund. The Western Gas Fund is comprised of shares of the Company's common stock, purchased in the open market by the trustee, Fidelity Management Trust Company, and short-term investments. A participant's ownership in the Western Gas Fund is measured in Units rather than in shares of common stock. To effectuate participant investment elections and therefore purchases and sales of Units, the trustee purchases and sells the common stock in the open market at market prices.
The Company is required to register the shares of common stock purchased by the trustee of the Retirement Plan under the Securities Act. Although all the purchases by the trustee were made in the open market and in a manner consistent with the Retirement Plan and the investment elections of the participants, the Company has determined that approximately 467,000 shares of its common stock purchased by the trustee beginning August 14, 2001 and ending August 14, 2002 (the "Rescission Period") may not have been properly registered in accordance with the Securities Act. These shares were purchased at an average price of $31.92 per share for total value of $14.9 million. The Company intends to correct this situation by filing a registration statement on Form S-3 with the SEC providing for a rescission offer to certain of the plan participants as described below. This registration statement is expected to be filed during the first quarter of 2004.
Any participant who elected to allocate a percentage of such participant's funds in the Retirement Plan to the purchase of Units in the Western Gas Fund at any time during the Rescission Period, and who still holds those Units during the period of the rescission offer, may direct a sale of those Units to the Company at the price the participant paid for the Units, plus interest. This election would be beneficial to any participant who purchased Units at a price higher than the Company's stock price during the period of the rescission offer. At December 31, 2003, the Company's common stock price was $47.25 per share. At December 31, 2003, approximately 144,000 shares of its common stock were held by the Western Gas Fund. The trustee of the Western Gas Fund sold the remaining 326,000 shares of the Company's common stock acquired during the Rescission Period. If a participant has already directed and caused the sale of those Units purchased during the Rescission Period at a loss, then the trustee or the participant may receive from the Company, the price paid for those Units, plus interest, less the sale proceeds. This election would be beneficial to any participant who sold Units at a loss.
While the Company is unable to estimate the cost or results of the rescission offer, it does not expect the costs to have a material adverse effect on its financial position, results of operations or cash flows. The Company also believes that the amounts subject to the rescission offer are immaterial for separate classification on the Consolidated Balance Sheet at December 31, 2003 and 2002.
Commitments.
Lease Commitments. As a normal course of the Company's business operations, the Company enters into operating leases for office space, office equipment, communication equipment and transportation equipment. In addition, primarily to support its growing development in the Powder River Basin coal bed development, the Company has entered into operating leases for compression equipment. These leases are classified as operating leases and have terms ranging from one month to ten years. The majority of the leases for compression have purchase options at various times throughout the primary terms of the agreements and have renewal provisions. Rental payments under operating leases have totaled $13.8 million, $10.8 million and $3.1 million in 2003, 2002 and 2001, respectively. Future operating lease payments by year under these leases are as follows (000s):
Firm Transportation Capacity. The Company enters into firm transportation agreements with interstate pipeline companies as a part of its marketing operations and to ensure that its equity production has access to downstream markets. At December 31, 2003, these agreements have terms ranging from one month to fourteen years. Payments under these agreements have totaled $26.4 million, $29.2 million and $8.8 million in 2003, 2002 and 2001, respectively. Future payments by year under these agreements are as follows (000s):
Storage Capacity. The Company enters into storage agreements with various third parties primarily as part of its marketing operations. To the extent that these contracts are in support of its marketing operations, the agreements are classified as derivatives in accordance with SFAS No. 133 and the difference between fair value and cost is included in income. Payments under these agreements totaled $5.2 million, $5.1 million and $3.9 million in 2003, 2002 and 2001, respectively. As of December 31, 2003, the Company had contracts in place for approximately 16.3 Bcf of storage capacity at various
third-party facilities. The associated contract periods have an average term of twenty-nine months. Future payments by year under these agreements are as follows (000s):
NOTE 9-BUSINESS SEGMENTS AND RELATED INFORMATION
The Company operates in four principal business segments, as follows: Gas Gathering, Processing and Treating; Exploration and Production; Transportation; and Marketing. Management separately monitors these segments for performance against its internal forecast and these segments are consistent with the Company's internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations.
Exploration and Production. The activities of the Exploration and Production segment include the exploration and development of gas properties primarily in the Rocky Mountain basins including those where the Company's gathering and/or processing facilities are located. The Marketing segment sells the majority of the production from these properties.
Gas Gathering, Processing and Treating. In this segment, the Company connects producers' wells (including those of its Exploration and Production segment) to its gathering systems for delivery to its processing or treating plants, processes the natural gas to extract NGLs and treats the natural gas in order to meet pipeline specifications. In some areas, where no processing is required, the Company gathers and compresses producers' gas and delivers it to pipelines for further delivery to market. Except for volumes taken in kind by the Company's producers, the Marketing segment sells the residue gas and NGLs extracted at most of its facilities. In this segment, the Company recognizes revenues for its services at the time the service is performed.
Substantially all gas flowing through the Company's gathering, processing and treating facilities is supplied under three types of contracts providing for the purchase, treating or processing of natural gas for periods ranging from one month to twenty years or in some cases for the life of the oil and gas lease. Approximately 79% of the Company's plant facilities' gross margins, or revenues at the plants less product purchases, for the month of December 2003 were under percentage-of-proceeds agreements in which it is typically responsible for the marketing of the gas and NGLs. The Company pays producers a specified percentage of the net proceeds received from the sale of the gas and NGLs.
Approximately 14% of the Company's plant facilities' gross margins for the month of December 2003 were under contracts that are primarily fee-based from which it receives a set fee for each Mcf of gas gathered and/or processed. This type of contract provides the Company with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to delay drilling.
Approximately 7% of the Company's plant facilities' gross margin for the month of December 2003 was under contracts with "keepwhole" arrangements or wellhead purchase contracts. The Company retains the NGLs recovered by the processing facility and keeps the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keepwhole" component of the contracts permits the Company to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, the Company is adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream.
Transportation. The Transportation segment reflects the operations of the Company's MIGC, Inc. and MGTC, Inc. pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas for its Marketing segment and other third parties. In this segment, the Company realizes revenue on a monthly basis from firm capacity contracts under which the shipper pays for transport capacity whether or not the capacity is used and from interruptible contracts where a fee is charged based upon volumes received into the pipeline. The Transportation segment's firm capacity contracts at December 31, 2003 range in duration from one month to five years.
Marketing. The Company's Marketing segment buys and sells gas and NGLs in the United States and Canada from and to a variety of customers. In this segment, revenues for sales of product are recognized at the time the gas or NGLs are delivered to the customer and are sensitive to changes in the market prices of the underlying commodities. The marketing of products purchased from third-parties typically results in low operating margins relative to the sales price. The Company sells its products under agreements with varying terms and conditions in order to match seasonal and other changes in demand. This segment also markets gas and NGLs produced by its gathering, processing, treating and production assets. Also included in this segment are its Canadian marketing operations, which are conducted through its wholly-owned subsidiary WGR Canada, Inc. and are immaterial for separate presentation.
During the years ended December 31, 2003, 2002 and 2001, the Company sold gas to a variety of customers including end-users, pipelines, energy merchants, local distribution companies and others. In 2003, no single customer accounted for more than approximately 6% of the Company's consolidated revenues from the sale of gas, or 5% of total consolidated revenue. In 2002, two customers accounted for approximately 10% of the Company's consolidated revenues from the sale of gas, or 9% of total consolidated revenue. One of these customers is an energy merchant and the other customer is an electric utility. In 2001, one customer accounted for approximately 5% of the Company's consolidated revenues from the sale of gas, or 4% of total consolidated revenue. This customer is a wholly owned subsidiary of a major integrated oil company.
During the years ended December 31, 2003, 2002 and 2001, the Company sold NGLs to a variety of customers including end-users, fractionators, chemical companies, energy merchants and other customers. In 2003, two customers accounted for approximately 49% of the Company's consolidated revenues from the sale of NGLs, or 6% of total consolidated revenue. One of these customers is a large integrated energy company and the other is a large petrochemical company. In 2002, three customers accounted for approximately 38% of the Company's consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue. One of these customers is a large integrated energy company, another is a large petrochemical company and the third is an energy merchant. In 2001, three customers accounted for approximately 37% of the Company's consolidated revenues from the sale of NGLs, or 5% of total consolidated revenue. These customers were all large integrated energy companies.
The following table sets forth the Company's segment information as of and for the three years ended December 31, 2003, 2002 and 2001 (000s). Due to the Company's integrated operations, the use of allocations in the determination of business segment information is necessary. Inter-segment revenues are valued at prices comparable to those of unaffiliated customers. Prior period amounts in the segment information have been reclassified to conform to the presentation used in 2003.
NOTE 10-EMPLOYEE BENEFIT PLANS
Retirement Plan. A discretionary retirement plan (a defined contribution plan) exists for all Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the board of directors, and during the three years ended December 31, 2003, the match of employee contributions was a sliding scale of 60% to 100% of the first 5% of employee compensation based upon years of service. Contributions are made to Fidelity Management Trust Company, as trustee. The trustee invests the funds in accordance with the participants' investment elections into mutual funds and a fund to purchase Company stock. The discretionary contributions made by the Company were $2.2 million, $1.9 million and $2.3 million, for the years ended December 31, 2003, 2002 and 2001, respectively. The matching contributions were approximately $1.4 million, $1.3 million and $1.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Key Employees' Incentive Stock Option Plan and 1987 Non-Employee Directors Stock Option Plan. Effective April 1987, the board of directors of the Company adopted a Key Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee Directors Stock Option Plan ("1987 Directors Plan") that authorized the granting of options to purchase 250,000 and 20,000 shares of the Company's common stock, respectively. Each of these plans has terminated. The Company loaned to certain employees, an amount sufficient to exercise their options under these plans. The loan and accrued interest were forgiven as the employee was continually employed by the Company and as resolved by the board of directors. As of December 31, 2002, loans related to 27,500 shares of common stock totaling $295,000 were outstanding under these terms. There were no loans outstanding as of December 31, 2003.
1999 Non-Employee Directors Stock Option Plan. Effective March 1999, the board of directors of the Company adopted a 1999 Non-Employee Directors' Stock Option Plan ("1999 Directors Plan") that authorized the granting of options to purchase 15,000 shares of the Company's common stock. During 1999, the board approved grants totaling 15,000 options to several board members. Under this plan, each of these options becomes exercisable as to 331/3% of the shares covered by it on each anniversary from the date of grant. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under the plan have been exercised in full.
1993, 1997 and 1999 Stock Option Plans. The 1993 Stock Option Plan ("1993 Plan"), the 1997 Stock Option Plan ("1997 Plan"), and the 1999 Stock Option Plan ("1999 Plan") became effective on March 29, 1993, May 21, 1997, and May 21, 1999, respectively, after approvals by the Company's stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section 422 of the Internal Revenue Code of 1986, as amended. The Company reserved 1,000,000 shares of common stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 750,000 shares of common stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan terminated on March 29, 2003. The 1997 Plan and the 1999 Plan will terminate on the earlier of May 21, 2007 and May 21, 2009, respectively, or the date on which all the respective options granted under each of the plans have been exercised in full. Although options covering 372,602 shares are available to be granted under the 1997 Plan, no further options will be granted under this plan.
Effective January 1, 2001, these plans were amended to allow for the exercise of stock options granted under these plans by the surrender to the Company of previously acquired shares of the Company's common stock. This amendment allows for the constructive exchange of Company stock already owned in payment for shares to be received under the option exercise. The price for the exchanged shares is the average closing price of the Company common stock for the ten days preceding the granting of an option.
Chief Executive Officer and President's Plan. Pursuant to the Employment Agreement, dated October 15, 2001, and the Stock Option Agreement, dated as of November 1, 2001, between the Company and Peter A. Dea, the Company's Chief Executive Officer and President, non-qualified stock options were granted for the purchase of 300,000 shares of the Company's common stock. The exercise price of the options was equal to $5.00 below the closing price per share on the effective date of the Employment Agreement. The stock options are subject to the conditions of the Agreements and vest equally over four years. The difference between the closing price on the effective date and the exercise price is being amortized over four years as compensation expense. This option plan will terminate on the earlier of October 15, 2010 or the date on which all options granted under the plan have been exercised in full.
2002 Non-Employee Directors Stock Option Plan. Effective May 2002, the stockholders approved the 2002 Non-Employee Directors' Stock Option Plan ("2002 Directors Plan") that authorized the granting of options to purchase 110,000 shares of the Company's common stock. The 2002 Directors Plan provides for a three-year vesting schedule while the non-employee director serves on the Company's board. Under this plan, a newly elected non-employee director will be granted 5,000 options to acquire common stock as of the date of election. The 2002 Directors Plan also provides for an annual grant on the date of the Company's annual meeting to each non-employee director of 2,000 options to acquire common stock. The purchase price of the stock under each option shall be the fair market value of the stock at the time such option is granted and no options shall be re-priced. The 2002 Directors Plan requires the non-employee director to exercise the option at the earlier of ten years from the date of the plan or within five years of the date each portion vests. The non-employee director's right to exercise options under the 2002 Directors Plan is subject to continuous service since the grant was made. If the non-employee director dies or becomes disabled (within the meaning of the 2002 Directors Plan) or a change of control occurs, then all of the options granted to the non-employee director shall become 100% exercisable. The 2002 Directors Plan will terminate on the earlier of May 17, 2012 or the date on which all options granted under the plan have been exercised in full. During 2003 and 2002, a total of 16,000 and 18,000 options, respectively, were granted under this plan.
2002 Stock Option Plan. Effective May 2002, the stockholders approved the 2002 Stock Incentive Plan ("2002 Plan") that authorized the granting of options to purchase 1,250,000 shares of the Company's common stock. No employee may be granted more than 125,000 options to acquire common stock in any fiscal year. The 2002 Plan requires the employee to exercise the option at the earlier of ten years from the date of the 2002 Plan or within five years of the date each portion vests. The employee's right to exercise options under the 2002 Plan is subject to continuous employment since the grant was made. If the employee dies, becomes disabled (within the meaning of the 2002 Plan) or a change of control occurs, then all of the options granted to the employee shall become 100% exercisable. The 2002 Plan will terminate on the earlier of May 17, 2012 or the date on which all options granted under the plan have been exercised in full. During 2003 and 2002, a total of 564,950 and 187,997 options, respectively, were granted under this plan.
Under each of the 1997, 1999 and 2002 plans, the board of directors of the Company determines and designates from time to time those employees of the Company to whom options are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The board of directors has the right to, among other things, fix the method by which the price is determined and the terms and conditions for the grant or exercise of any option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1997, 1999 and 2002 Plans, the board of directors has the authority to set the vesting schedule from 20% per year to 331/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests.
In March 1999, certain officers of the Company were granted a total of 300,000 options, which vested ratably over the next three years, under the 1997 Plan. The exercise price of $5.51 per share was determined by using the average stock price for the ten trading days prior to the grant date. In exchange, these officers were required to relinquish a total of 246,200 vested and unvested options at prices ranging from $18.63 to $34.00 per share.
The following table summarizes the number of stock options exercisable and available for grant under the Company's benefit plans:
The following table summarizes the stock option activity under the Company's benefit plans:
The following table summarizes the weighted average option exercise price information under the Company's benefit plans:
NOTE 11-SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
Costs. The following tables set forth capitalized costs at December 31, 2003, 2002 and 2001 and costs incurred for oil and gas producing activities for the years ended December 31, 2003, 2002 and 2001 (000s):
Results of Operations. The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 2003, 2002 and 2001 are as follows (000s):
Reserve Quantity Information. Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of
economically recoverable reserves and of future net cash flows expected there from prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations.
The following table sets forth information for the years ended December 31, 2003, 2002 and 2001 with respect to changes in the Company's proved developed and undeveloped reserves, all of which are in the United States.
Standardized Measures of Discounted Future Net Cash Flows. Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.
Future cash inflows are computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves.
The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company's expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Also included in this caption are asset retirement obligations.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.
An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 2003, 2002 and 2001 is as follows (000s):
Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 2003, 2002 and 2001 are as follows (000s):
NOTE 12-QUARTERLY RESULTS OF OPERATIONS (UNAUDITED):
The following summarizes certain quarterly results of operations (000s, except per share amounts):
(a)Excludes selling and administrative, interest and income tax expenses, (gains) or losses on sale of assets and the cumulative effect of the change in accounting principle.
NOTE 13-GUARANTOR AND NON-GUARANTOR SUBSIDIARIES:
The Company's payment obligations under its Revolving Credit Facility, its Master Shelf Agreement and its Senior Subordinated Notes (collectively the "Financing Facilities") are fully and unconditionally guaranteed by its significant subsidiaries to the extent allowed by applicable law. These guarantees are joint and several and, in the case of the Senior Subordinated Notes, are subordinated in right of payment to senior debt of the guarantors.
During the years ended December 31, 2003, 2002 and 2001, the guarantors of the Company's payment obligations under its financing facilities were Lance Oil & Gas Company, Inc., Western Gas Resources-Texas, Inc., Mountain Gas Resources, Inc., MIGC, Inc., MGTC, Inc. and Western Gas Wyoming, L.L.C. (collectively, the "Guarantor Subsidiaries").
The Company's subsidiaries that did not guarantee the Company's payment obligations under its financing facilities during the years ended December 31, 2003, 2002 and 2001 included Western Power Services, Inc., Western Gas Resources-Westana, Inc. and WGR Canada, Inc., and Western Gas Resources-Sand Wash, Inc. (collectively, the "Non-Guarantor Subsidiaries").
Presented below is condensed consolidating financial information for Western Gas Resources, Inc. (the "Parent Company"), the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries. Balance sheet data are presented as of December 31, 2003 and 2002. The Statement of Operations and Statement of Cash Flows data are presented for the years ended December 31, 2003, 2002 and 2001.
For purposes of the following tables, the Parent Company's investments in its subsidiaries are accounted for using the equity method of accounting. Net income of Guarantor and Non-Guarantor Subsidiaries is, therefore, reflected in the Parent Company column under Earnings from equity investments. Selling and administrative expense and Provision for income taxes are primarily reflected in the Parent Company column. The Consolidating Entries eliminate the investments in the subsidiaries and other inter-company transactions for consolidated reporting purposes.
Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2003
(000s)
Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2003
(000s)
Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2003
(000s)
Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2002
(000s)
Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2002
(000s)
Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2002
(000s)
Supplemental Condensed Consolidating Statement of Operations
For the year ended December 31, 2001
(000s)
Supplemental Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2001
(000s)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Under the direction of the Chief Executive Officer and President and the Executive Vice President-Chief Financial Officer, we have reviewed and evaluated our disclosure controls and procedures and believe, as of the date of management's evaluation, that our disclosure controls and procedures are reasonably designed to be effective for the purposes for which they are intended. The review and evaluation was performed within 90 days prior to the filing of this report.
There have not been any changes in our internal controls or any other factors that could significantly affect these controls subsequent to the date of management's evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Based on their evaluation of the Company's disclosure controls and procedures as of the end of the period covered by this report, the Company's Chief Executive Officer and President and the Executive Vice-President-Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective in ensuring that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are omitted because the Company will file a definitive proxy statement (the "Proxy Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the Proxy Statement to be so filed for the Company's annual meeting of stockholders scheduled for May 7, 2004 and is hereby incorporated by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)The following documents are filed as part of this report:
(1)Financial Statements:
Reference is made to page 40 for a list of all financial statements filed as a part of this report.
(2)Financial Statement Schedules:
None required.
(3)Exhibits:
3.1
Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.1 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.2
Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (previously filed as Exhibit 3.2 to our Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference).
3.3
Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock (previously filed as part of Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
3.4
Certificate of Designation of the $2.625 Cumulative Convertible Preferred Stock of Western Gas Resources, Inc. (previously filed in our Current Report on Form 8-K filed on February 25, 1994 and incorporated herein by reference).
3.5
Amended and Restated Bylaws of Western Gas Resources, Inc., adopted by the Board of Directors on April 7, 2003 (previously filed as Exhibit 3.5 to our Quarterly Report on Form 10-Q filed on May 14, 2003 and incorporated herein by reference).
4.1
Rights Agreement, dated as of March 22, 2001 between Western Gas Resources, Inc., and Fleet National Bank as Rights Agent, including exhibits thereto (previously filed as Exhibit 1 to our Form 8-A filed on March 30, 2001 and incorporated herein by reference).
4.2
Indenture between Western Gas Resources, Inc. and Guarantors to Chase Bank of Texas, National Association, Trustee for $225,000,000 Senior Subordinated Notes Due 2009, dated June 15, 1999 (previously filed as Exhibit 28 to our Quarterly Report on Form 10-Q filed on August 13, 1999 and incorporated herein by reference).
4.3
Western Gas Resources, Inc. First Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated October 19, 1999 (previously filed as Exhibit 4.10 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
4.4
Western Gas Resources, Inc. Second Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated September 29, 2000 (previously filed as Exhibit 4.11 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
4.5
Western Gas Resources, Inc. Third Supplemental Indenture to 10% Senior Subordinated Notes due 2009 dated January 3, 2001 (previously filed as Exhibit 4.12 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
10.1
Registration Rights Agreement among Western Gas Resources, Inc., WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and Sauvage Gas Service, Inc. (previously filed as Exhibit 10.14 to our Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference).
10.2
Amendment No. 1 to Registration Rights Agreement, dated as of May 1, 1991, between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean Phillips, Inc., Heetco, Inc. NV, Sauvage Gas Company and Sauvage Gas Service, Inc. (previously filed as Exhibit 4.2 to our Quarterly Report on Form 10-Q filed for the quarter ended June 30, 1991 and incorporated herein by reference).
10.3
Agreement to provide loans to exercise key employees' common stock options (previously filed as Exhibit 10.26 to our Annual Report on Form 10-K filed for the fiscal year ended December 31, 1991 and incorporated herein by reference).*
10.4
Second Amended and Restated Master Shelf Agreement, effective January 31, 1996, by and between Western Gas Resources, Inc. and Prudential Company of America (previously filed as Exhibit 10.49 to our Annual Report on Form 10-K filed on March 22, 1996 and incorporated herein by reference).
10.5
Letter Amendment No. 1, dated November 21, 1997, to the Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company.
10.6
Letter Amendment No. 2, dated March 31, 1999, to the Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company (previously filed as Exhibit 10.22 to our Quarterly Report on Form 10-Q filed on May 13, 1999 and incorporated herein by reference).
10.7
Limited Waiver, Consent, Release and Amendment No. 3 to the Second Amended and Restated Master Shelf Agreement, entered into as of June 1, 1999, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company (previously filed as Exhibit 10.14 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference.)
10.8
Limited Waiver, Consent, Release and Amendment No. 4 to the Second Amended and Restated Master Shelf Agreement, dated August 25, 2000, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company (previously filed as Exhibit 10.24 to our Quarterly Report on Form 10-Q filed on November 13, 2000 and incorporated herein by reference).
10.9
Waiver and Consent to the Second Amended and Restated Master Shelf Agreement, dated November 22, 2000, by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America and Pruco Life Insurance Company (previously filed as Exhibit 10.20 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
10.10
Letter Amendment No. 5, dated March 30, 2001, to the Second Amended and Restated Master Shelf Agreement, by and between Western Gas Resources, Inc., and The Prudential Insurance Company of America (previously filed as Exhibit 10.25 to our Quarterly Report on Form 10-Q filed on May 14, 2001 and incorporated herein by reference).
10.11
Letter Amendment No. 6, dated March 1, 2002, to the Second Amended and Restated Master Shelf Agreement by and among Western Gas Resources, Inc., and The Prudential Insurance Company of America and Pruco Life Insurance Company (previously filed as Exhibit 10.27 to our Quarterly Report on Form 10-Q filed on May 14, 2002 and incorporated herein by reference).
10.12
Third Amended and Restated Master Shelf Agreement, dated as of December 19, 1991 (effective as of January 13, 2003), by and among Western Gas Resources, Inc. and The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management Company, Inc. and ING Life Insurance & Annuity Company (previously filed as Exhibit 10.29 to our Annual Report on Form 10-K filed on March 24, 2003 and incorporated herein by reference).
10.13
Letter Amendment No. 1 to Third Amended and Restated Master Shelf Agreement, dated as of April 24, 2003, by and among Western Gas Resources, Inc., The Prudential Insurance Company of America, Pruco Life Insurance Company, Prudential Investment Management, Inc. and ING Life Insurance & Annuity Company (previously filed as Exhibit 10.5 to our Quarterly Report on Form 10-Q filed on May 13, 2003 and incorporated herein by reference).
10.14
Loan Agreement, dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders (previously filed as Exhibit 10.20 to our Quarterly Report on Form 10-Q filed on May 13, 1999 and incorporated herein by reference).
10.15
First Amendment, dated June 10, 1999 to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank as Agent, and the Lenders (previously filed as Exhibit 10.15 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
10.16
Second Amendment, dated November 22, 1999, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders.
10.17
Third Amendment, dated April 27, 2000, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders (previously filed as Exhibit 10.23 to our Quarterly Report on Form 10-Q filed on May 12, 2000 and incorporated herein by reference).
10.18
Fourth Amendment, dated August 25, 2000, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank, as Agent, and the Lenders (previously filed as Exhibit 10.25 to our Quarterly Report on Form 10-Q filed on November 13, 2000 and incorporated herein by reference).
10.19
Fifth Amendment, dated November 22, 2000, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders (previously filed as Exhibit 10.19 to our Annual Report on Form 10-K filed on March 15, 2001 and incorporated herein by reference).
10.20
Sixth Amendment, dated April 26, 2001, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc., and NationsBank, as agent, and the Lenders (previously filed as Exhibit 10.24 to our Quarterly Report on Form 10-Q filed on May 14, 2001 and incorporated herein by reference).
10.21
Seventh Amendment, dated September 27, 2001, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc., and NationsBank, as agent, and the Lenders (previously filed as Exhibit 10.25 to our Annual Report on Form 10-K filed on March 15, 2002 and incorporated herein by reference).
10.22
Eighth Amendment, dated February 25, 2002, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders (previously filed as Exhibit 10.26 to our Quarterly Report on Form 10-Q filed on May 14, 2002 and incorporated herein by reference).
10.23
Ninth Amendment, dated April 25, 2002, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders (previously filed as Exhibit 10.28 to our Quarterly Report on Form 10-Q filed on May 14, 2002 and incorporated herein by reference).
10.24
Tenth Amendment, dated January 3, 2003, to Loan Agreement dated April 29, 1999, by and among Western Gas Resources, Inc., and Bank of America, N.A. (formerly NationsBank) as agent and the Lenders (previously filed as Exhibit 10.28 to our Annual Report on Form 10-K filed on March 24, 2003 and incorporated by reference herein).
10.25
Credit Agreement, dated as of April 24, 2003, among Western Gas Resources, Inc., as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Bank One, NA and Fleet National Bank, as Co-Syndication Agents, The Royal Bank of Scotland plc and Wachovia Bank, National Association, as Co-Documentation Agents, and the Other Lenders Party Thereto (previously filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q filed on May 13, 2003 and incorporated by reference herein).
10.26
Intercreditor Agreement, dated April 26, 2001, by and among Western Gas Resources, Inc., Bank of America, N. A., and The Prudential Insurance Company of America (previously filed as Exhibit 10.26 to our Quarterly Report on Form 10-Q filed on May 14, 2001 and incorporated herein by reference).
10.27
Intercreditor Agreement, dated as of April 24, 2003, by and among the banks (as defined therein), Bank of America, N.A., as Administrative Agent for the banks and The Prudential Insurance Company of America, Pruco Life Insurance Company, ING Life Insurance & Annuity Company and Prudential Investment Management, Inc., consented to agreed by Western Gas Resources, Inc. and its subsidiaries listed therein (previously filed as Exhibit 10.3 to Western Gas Resources, Inc., 10-Q dated March 31, 2002 and incorporated herein by reference).
10.28
Restated Retirement Plan of Western Gas Resources, Inc., dated May 1, 2001, (previously filed as Exhibit 4.9 to our Registration Statement on Form S-8 filed on August 14, 2002 and incorporated herein by reference).
10.29
Western Gas Resources, Inc., 1997 Stock Option Plan.*
10.30
First Amendment to the Western Gas Resources, Inc. 1997 Stock Option Plan.*
10.31
Second Amendment to the Western Gas Resources, Inc. 1997 Stock Option Plan.*
10.32
Western Gas Resources, Inc., 1999 Stock Option Plan.* (Previously filed as Exhibit 4.7 to our Registration Statement on Form S-8, Registration No. 333-95255, filed on January 24, 2000 and incorporated herein by reference.)
10.33
First Amendment to the Western Gas Resources, Inc. 1999 Stock Option Plan.*
10.34
Second Amendment to the Western Gas Resources, Inc. 1999 Stock Option Plan.*
10.35
Western Gas Resources, Inc. 2002 Stock Option Plan.*
10.36
First Amendment to the Western Gas Resources, Inc. 2002 Stock Option Plan.*
10.37
Western Gas Resources, Inc. Non-Employee Director's Stock Option Plan.* (Previously filed as part of Exhibit 4.7 to our Registration Statement on Form S-8, Registration No. 333-95259, filed on January 24, 2000 and incorporated herein by reference).
10.38
Western Gas Resources, Inc. 2002 Non-Employee Director's Stock Option Plan.*
10.39
Stock Option Agreement, effective November 1, 2001, by and between Western Gas Resources, Inc. and Peter A. Dea (previously filed as Exhibit 99.1 to our Registration Statement on Form S-8 filed on December 21, 2002, and incorporated herein by reference).*
10.40
Agreement, dated November 1, 2001, by and between Western Gas Resources, Inc., and Lanny F. Outlaw (previously filed as Exhibit 10.7 to our Quarterly Report on Form 10-Q filed on November 13, 2001 and incorporated herein by reference).*
10.41
2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and Edward A. Aabak, together with 2001 Indemnification Agreement.*
10.42
2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and John F. Chandler, together with 2001 Indemnification Agreement.*
10.43
2001 Employment Agreement, dated October 15, 2001, by and between Western Gas Resources, Inc. and William J. Krysiak, together with 2001 Indemnification Agreement.*
10.44
2001 Employment Agreement, dated June 14, 2001, by and between Western Gas Resources, Inc. and John C. Walter, together with 2001 Indemnification Agreement.*
11.1
Statement regarding computation of per share earnings.
21.1
List of Subsidiaries of Western Gas Resources, Inc.
23.1
Consent of PricewaterhouseCoopers LLP.
23.2
Consent of Netherland, Sewell & Associates, Inc.
31.1
Section 302 Certification of the Chief Executive Officer.
31.2
Section 302 Certification of the Chief Financial Officer.
32.1
Section 906 Certification of the Chief Executive Officer and Chief Financial Officer.
*Management contract or compensating plan or arrangement.
Indicates exhibits filed with this Form 10-K.
(b)Reports on Form 8-K:
During the quarter ended December 31, 2003, we filed the following Current Reports on Form 8-K:
•Report filed on October 24, 2003, announcing settlement of litigation with Williams Production RMT Company.
•Report filed on November 7, 2003, announcing that the Company has called for redemption 700,000 outstanding shares of its $2.625 Cumulative Convertible Preferred Stock.
•Report furnished on November 12, 2003, announcing the Company's third quarter 2003 results.
•Report filed on December 22, 2003, announcing that the Company has called for redemption 800,000 outstanding shares of its $2.625 Cumulative Convertible Preferred Stock.
(c)Exhibits required by Item 601 of Regulation S-K. See (a) (3) above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado on March 9, 2004.
WESTERN GAS RESOURCES, INC.
(Registrant)
By:
/s/ PETER A. DEA Peter A. Dea
Chief Executive Officer, President and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ PETER A. DEA Peter A. Dea
Chief Executive Officer, President and Director (Principal Executive Officer)
March 9, 2004
/s/ WILLIAM J. KRYSIAK William J. Krysiak
Executive Vice President-Chief Financial Officer (Principal Financial and Accounting Officer)
March 9, 2004
/s/ JAMES A. SENTY James A. Senty
Chairman of the Board
March 9, 2004
/s/ WALTER L. STONEHOCKER Walter L. Stonehocker
Vice Chairman of the Board
March 9, 2004
/s/ DEAN PHILLIPS Dean Phillips
Director
March 9, 2004
/s/ JOSEPH E. REID Joseph E. Reid
Director
March 9, 2004
/s/ RICHARD B. ROBINSON Richard B. Robinson
Director
March 9, 2004
/s/ BILL M. SANDERSON Bill M. Sanderson
Director
March 9, 2004
/s/ WARD SAUVAGE Ward Sauvage
Director
March 9, 2004
/s/ BRION G. WISE Brion G. Wise
Director
March 9, 2004