-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NjfQuBTUT2joJPieqtS8PvcaWqkFsr3ZzSbuAvV+J1jBlf7C3g9IHHQIZKN2lmJX hU9Adi0WbutHyG1tRNvLFQ== 0000950134-03-003193.txt : 20030228 0000950134-03-003193.hdr.sgml : 20030228 20030227213321 ACCESSION NUMBER: 0000950134-03-003193 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20030227 ITEM INFORMATION: Other events FILED AS OF DATE: 20030228 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTPORT RESOURCES CORP /NV/ CENTRAL INDEX KEY: 0000889005 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 133869719 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-14256 FILM NUMBER: 03584493 BUSINESS ADDRESS: STREET 1: 767 FIFTH AVE STREET 2: 46TH FL CITY: NEW YORK STATE: NY ZIP: 10153 BUSINESS PHONE: 2126442200 MAIL ADDRESS: STREET 1: 767 FIFTH AVE STREET 2: 46TH FL CITY: NEW YORK STATE: NY ZIP: 10153 FORMER COMPANY: FORMER CONFORMED NAME: BELCO OIL & GAS CORP DATE OF NAME CHANGE: 19960207 8-K 1 d03632e8vk.txt FORM 8-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of report (Date of earliest event reported): FEBRUARY 27, 2003 WESTPORT RESOURCES CORPORATION (Exact Name of Registrant as Specified in Charter) NEVADA 001-14256 13-3869719 (State or Other Jurisdiction (Commission (IRS Employer of Incorporation) File Number) Identification No.) 1670 BROADWAY STREET SUITE 2800 DENVER, COLORADO 80202 (Address and Zip Code of Principal Executive Offices) (303) 573-5404 (Registrant's telephone number, including area code) ITEM 5. OTHER EVENTS. On February 24, 2003, Westport Resources Corporation, a Nevada corporation, also referred to as Westport or the Company, announced earnings and record production, EBITDAX and discretionary cash flow for the year and quarter ended December 31, 2002. Net loss available to common stockholders was approximately $33.3 million, or $0.63 per basic share ($0.63 per fully diluted share) in 2002, compared to net income available to common stockholders in 2001 of approximately $48.2 million or $1.11 per basic share ($1.09 per fully diluted share). During the fourth quarter of 2002, net loss available to common stockholders was approximately $14.9 million, or $0.27 per basic share ($0.27 per fully diluted share), compared to a net loss of approximately $13.8 million or $0.27 per basic share ($0.27 per fully diluted share) for the corresponding period in 2001. Earnings were adversely affected in the 12 and three months ended December 31, 2002 as a result of non-cash charges relating to Westport's commodity price risk management activity and property impairments. In 2002, the Company reported a loss in non-cash, non-hedge change in fair market value of derivatives of $26.7 million, of which $17.8 million was recorded in the fourth quarter, and recorded impairments to proved and unproved properties in 2002 of $29.7 million, of which $20.6 million pertains to the fourth quarter. Westport's production for the 12 months and three months ended December 31, 2002 increased to record levels, averaging approximately 356 Mmcfe/d for the year, compared to approximately 242 Mmcfe/d for 2001, and approximately 377 Mmcfe/d for the quarter, compared to 353 Mmcfe/d for the same period in 2001. The increase in both the fourth quarter and annual production in 2002 is primarily due to the acquisition of producing properties in southeast Texas and the Greater Natural Buttes area of Utah and the results of our drilling program. As a result of increased production and strong commodity prices, Westport reported record EBITDAX and discretionary cash flow in 2002 of approximately $284.7 million and $254.3 million, respectively, compared to $245.0 million and $230.2 million, respectively, in 2001. In the fourth quarter of 2002, EBITDAX and discretionary cash flow were approximately $94.1 million and $86.9 million, respectively, compared to $69.9 million and $61.0, respectively in 2001. EBITDAX and discretionary cash flow are presented herein because of their wide acceptance as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. For a detailed summary of each, please refer to the calculations and definitions in the Supplemental Data section attached below. "In 2002, we successfully executed three significant acquisitions, adding over 700 Bcfe to our asset base for a 70% increase in proved reserves," commented Donald D. Wolf, Chairman and Chief Executive Officer of Westport. "In the final transaction of the year, we acquired a long-lived legacy asset in the Greater Natural Buttes area of Utah providing us with numerous drilling opportunities to grow the company's reserve, production and cash flow in 2003 and beyond. Concurrent with the acquisitions, we completed a number of capital market transactions allowing us to maintain our strong financial position and flexibility." Before the effects of commodity price risk management settlements, average realized oil prices increased 9% in 2002 to $23.66 from $21.69 in 2001 per barrel of oil, while average realized natural gas prices decreased 18% from $3.59 per Mcf of natural gas in 2001 to $2.94 in 2002. In the fourth quarter of 2002, Westport's average realized oil and natural gas prices increased 46% and 55%, respectively, from $17.67 per barrel of oil and $2.34 per Mcf of natural gas in the fourth quarter of 2001 to $25.81 per barrel of oil and $3.63 per Mcf of natural gas in the fourth quarter of 2002. OPERATIONAL SUMMARY Estimated proved reserves at December 31, 2002 increased nearly 70% from the previous year to approximately 1,580 Bcfe with a pre-tax net present value of proved reserves discounted at 10% of $2.4 billion using year-end NYMEX prices of $31.23 per barrel of oil and $4.58 per Mmbtu of natural gas. Westport's reserves were comprised of 1,105 Bcf of gas and 79 million barrels of oil, with 66% being classified as proved developed. Westport's finding and development costs from all sources including acquisitions were $0.98 per Mcfe, and the Company replaced 600% of production from all sources. Westport's three year average production replacement ratio and average all sources finding, development and acquisition cost are 561% and $1.30 per Mcfe, respectively. In 2002, Westport's capital expenditures, excluding amounts attributed to acquisitions, were approximately $163.5 million, with approximately 63% allocated to development and 37% allocated to exploration. Of this amount, approximately $28.4 million was attributable to the Northern Division, approximately $42.0 million was attributable to the Southern Division, and approximately $93.1 million was attributable to the Gulf of Mexico Division. During 2002, Westport participated in 200 development wells, of which 97% were successful, and 19 exploration wells, of which 32% were successful. In the fourth quarter of 2002, Westport drilled 40 development wells, of which 95% were successful, and eight exploration wells, of which 25% were successful. At year-end, four exploratory wells and five development wells were drilling, two exploratory well and five development wells were being completed and one development well was waiting on completion. WESTERN DIVISION The Western Division was formed as a result of the December 17, 2002 acquisition of producing properties and midstream assets located in the Greater Natural Buttes area of Utah. During the brief period that Westport operated these properties in 2002, net production averaged 68 Mmcfe/d. At December 31, 2002 the Western Division reported total proved reserves of 596 Bcfe, 99% of which were natural gas, with a pre-tax net present value discounted at 10% of $555 million. The Company operates 88% of the net present value of these properties and owns interests in approximately 240,000 net undeveloped acres of leasehold in the Uinta Basin. Since closing the transaction, Westport initiated its drilling program with three rigs, one of which is targeting deeper horizons between 10,000 and 13,000 feet to evaluate the lower Mesaverde and Mancos formations. Thus far, Westport has participated in the drilling of eight development wells and conducted 15 recompletions and workovers in the Greater Natural Buttes area since assuming operations late last year. The Company currently has a total of 141 drilling permits, 86 permits filed and awaiting approval and an additional 124 operated locations are in the permitting process. To lead the newly formed Division, Westport appointed Carter Mathies as Vice President and General Manager of the Western Division. Mr. Mathies has over 20 years of experience in the oil and gas industry in managing and operating both upstream and midstream operations. Prior to joining Westport, Mr. Mathies was Vice President of Kinder Morgan Energy Partners, where he had operating responsibility for Kinder Morgan's gathering and processing unit. Prior to his tenure at Kinder Morgan, Mr. Mathies was President and CEO of Tipperary Corporation, a publicly traded independent exploration and production company. NORTHERN DIVISION In the Northern Division, which conducts operations in the Rocky Mountain region primarily in Wyoming and North Dakota, net production for the fourth quarter of 2002 averaged approximately 107 Mmcfe/d, compared to approximately 110 Mmcfe/d for the full year. In 2001, net production for the fourth quarter averaged 100 Mmcfe/d compared to 75 Mmcfe/d for the full year. At year-end 2002, the Northern Division reported proved reserves of 353 Bcfe, 42% of which is natural gas, with a pre-tax net present value discounted at 10% of $515 million. Westport drilled 126 development wells in the Northern Division in 2002, of which 98% were successful, and three exploration wells, of which 33% were successful. In 2002, Westport continued its horizontal drilling program in the Williston Basin of North Dakota, drilling 17 re-entry wells in the Wiley, Horse Creek and Bear Creek fields. Net production in the Williston Basin for 2002 increased approximately 23% to approximately 50 Mmcfe/d, accounting for approximately 47% of the Northern Division's production. In the Moxa Arch and Wamsutter areas of southwestern Wyoming, Westport operates 191 wells and owns a working interest in over 450 wells. Fourth quarter 2002 net production in the region averaged approximately 26 Mmcfe/d. The Company owns interests in approximately 108,000 gross and 50,000 net developed acres in these fields. Thus far in 2003, the Northern Division has participated in eight development wells and two exploration wells, of which three are producing, four are currently completing, two are drilling and one exploration well was unsuccessful. SOUTHERN DIVISION In the Southern Division, which conducts operations in the Permian Basin, Mid-Continent and onshore Gulf Coast regions, net production for the fourth quarter of 2002 averaged approximately 151 Mmcfe/d, compared to approximately 135 Mmcfe/d for the full year. In 2001, net production for the fourth quarter averaged 145 Mmcfe/d compared to 64 Mmcfe/d for the full year. At year-end 2002, the Southern Division reported proved reserves of 476 Bcfe, 54% of which is natural gas, with a pre-tax net present value discounted at 10% of $877 million. Westport drilled 65 development wells in the Southern Division in 2002, of which 99% were successful, and four exploration wells, of which 50% were successful. Development of the Elm Grove Field continued with net production increasing throughout the year averaging approximately 17 Mmcfe/d in the fourth quarter of 2002. In 2002, the Company drilled 24 development wells in the Elm Grove field, all of which were successful. Westport owns an approximate 37% working interest in the field. Development and exploration activity continued in the Gulf Coast region of southeast Texas, where Westport acquired oil and gas producing properties in September 2002 for approximately $120 million. The properties are currently producing 35 Mmcfe/d, an increase from 28 Mmcfe/d at the time of the acquisition. In this region, Westport primarily focuses its activity in the Yegua trend. Since closing the transaction, the Company has brought on-line one exploratory well and two development wells. In this area, the Company owns interests in approximately 10,000 net undeveloped acres and in the fourth quarter of 2002, commenced two 3-D seismic acquisition programs covering over 185 square miles combined. Thus far in 2003, the Southern Division has participated in 21 development wells and three exploration wells, of which seven are producing, nine are completing, four are drilling, three wells were unsuccessful and one exploration well was shut-in. GULF OF MEXICO DIVISION In the Gulf of Mexico Division, net production for the fourth quarter averaged approximately 108 Mmcfe/d, compared to approximately 109 Mmcfe/d for the full year. In 2001, net production for the fourth quarter averaged approximately 108 Mmcfe/d compared to 102 Mmcfe/d for the full year. At year-end 2002, the Gulf of Mexico Division reported proved reserves of approximately 155 Bcfe, 71% of which is natural gas, with a pre-tax net present value discounted at 10% of $459 million. Westport drilled nine development wells in the Gulf of Mexico Division in 2002, of which 78% were successful, and 12 exploration wells, of which 25% were successful. In the West Cameron 180/198 complex, the Company's major producing field offshore, fourth quarter 2002 production averaged approximately 36 Mmcfe/d, compared to 34 Mmcfe/d for the full year. In High Island Block 197, Westport owns a 25% non-operated working interest and participated in two development wells and one exploration well in 2002. Net production during the fourth quarter of 2002 averaged approximately 18 Mmcfe/d compared to 8 Mmcfe/d for the full year. In South Timbalier Block 316, construction of the production platform is proceeding on schedule and within the allocated budget. Westport anticipates completing platform installation by the end of the second quarter of 2003 and expects production to commence in the second half of 2003. Thus far in 2003, the Gulf of Mexico Division has participated in three exploration wells, of which one is currently completing and two are drilling. COMMODITY PRICE RISK MANAGEMENT For the 12 months ended December 31, 2002 and 2001, Westport recorded a hedge settlement loss of $1.3 million and a gain of $2.1 million, respectively. For the three months ended December 31, 2002 and 2001, the Company recorded a hedge settlement loss of $2.8 million and a gain of $3.9 million, respectively. For the 12 months ended December 31, 2002, Westport recorded a non-hedge settlement gain of $0.8 million compared to $15.3 million in 2001. The Company did not record a non-hedge settlement in the fourth quarter of 2002, while recording a gain of $15.9 million in the fourth quarter of 2001. In 2002, the Company recorded a loss in non-cash, non-hedge change in fair market value of derivatives of $26.7 million, of which $17.8 million was recorded in the fourth quarter. In 2001, Westport recorded a gain in non-cash, non-hedge, change in fair market value of derivatives of $14.3 million and a loss of $10.2 million in the fourth quarter of 2001. The majority of the non-cash, non-hedge change in fair market value of derivatives charges in 2002 relates to contracts entered into before closing the acquisition of the Greater Natural Buttes assets to cover a portion of the expected production through 2005. Upon the closing of the transaction, the derivative contracts qualified for hedge accounting treatment. As of February 19, 2003, Westport had approximately 5.2 million barrels of oil and 73.7 Bcf of natural gas subject to commodity price risk management ("CPRM") contracts for 2003. Of these contracts, all of the oil and 63.4 Bcf of the natural gas contracts are subject to weighted average NYMEX floor prices of $23.18 per barrel and $3.78 per Mmbtu and weighted average NYMEX ceiling prices of $25.16 per barrel and $4.20 per Mmbtu, respectively, excluding the effect of any three-way floor prices. Of the remaining 2003 gas CPRM contracts, 7.3 Bcf have settlements that are calculated based on the Northwest Pipeline Rocky Mountain Index ("NWPRM") with weighted average NWPRM floor and ceiling prices of $3.00 and $3.29, respectively. The remaining 2003 gas CPRM contract settlements are calculated based on the Colorado Interstate Gas Rocky Mountain Index ("CIGRM") with a weighted average swap price of $3.59. In addition, included in the 63.4 Bcf of natural gas contracts, the Company has entered into basis swaps covering 13.4 Bcf of natural gas for 2003 that lock in the pricing differential between NYMEX and NWPRM at a weighted average price differential of $0.67 per Mmbtu and 3.7 Bcf for 2003 that lock in the pricing differential between NYMEX and CIGRM at a weighted average price differential of $0.95 per Mmbtu. The Company has approximately 2.2 million barrels of oil and 49.3 Bcf of natural gas subject to CPRM contracts for 2004. Of these contracts, all of the oil and 38.3 Bcf of the natural gas contracts are subject to weighted average NYMEX floor prices of $23.93 per barrel and $3.83 per Mmbtu and weighted average NYMEX ceiling prices of $25.47 per barrel and $4.06 per Mmbtu, respectively, excluding the effect of any three-way floor prices. The remaining 2004 gas CPRM contract settlements are calculated based on the NWPRM index with weighted average swap price of $3.33. In addition, included in the 38.3 Bcf of natural gas contracts, the Company has entered into basis swaps covering 3.7 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and NWPRM at a weighted average price differential of $0.66 per Mmbtu and 1.8 Bcf of natural gas for 2004 that lock in the pricing differential between NYMEX and CIGRM at a weighted average price differential of $0.81 per Mmbtu. The Company has approximately 9.1 Bcf of natural gas subject to CPRM contracts for 2005 with a weighted average NYMEX swap price of $3.96 per Mmbtu. The contracts discussed above represent the Company's hedge and non-hedge positions. As of February 24, 2003 Westport has posted letters of credit or cash of $118.8 million as a result of its margin requirements on these contracts. For a detailed summary of commodity price risk management contracts, please refer to the Commodity Price Risk Management table attached below. Westport is an independent energy company engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the Gulf of Mexico, the Rocky Mountains, Permian Basin/Mid-Continent and the Gulf Coast. FORWARD - LOOKING STATEMENTS This Current Report on Form 8-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact, such as anticipated dates of first production, estimated reserves, projected drilling and development activity, projected production, projected cash flow and projected capital expenditures. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including the risks and uncertainties inherent in the Company's business and other cautionary statements set forth in the filings of the Company with the Securities and Exchange Commission, including without limitation the Company's most recent Annual Report on Form 10-K. These risks include, among others, oil and gas price volatility, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of proved reserves and in projections of future rates of production and timing of development expenditures, environmental risks, regulatory changes, general economic conditions, risks of assimilating the acquired properties and the actions or inactions of third-party operators. The Company does not undertake any obligation to update any forward-looking statements contained in this Current Report on Form 8-K. SUMMARY DATA (in thousands except per share data)
FOR THE THREE MONTHS ENDED FOR THE YEAR ENDED DECEMBER 31, DECEMBER 31, ---------------------------- ---------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ Production Oil (Mbbls) 2,028 1,854 7,927 4,929 Natural gas (Mmcf) 22,473 21,385 82,346 58,562 Mmcfe 34,641 32,509 129,908 88,136 Average Daily Production Oil (Mbbls/d) 22.0 20.2 21.7 13.5 Natural gas (Mmcf/d) 244.3 232.4 225.6 160.4 Mmcfe/d 376.5 353.4 355.9 241.5 Average prices Oil (per bbl) $ 25.81 $ 17.67 $ 23.66 $ 21.69 Natural gas (per Mcf) 3.63 2.34 2.94 3.59 Hedging effect (per Mcfe) (0.08) .14 (0.01) .03 Oil and natural gas sales $ 133,818 $ 82,873 $ 429,260 $ 317,278 Lease operating expense 21,947 20,545 89,328 55,315 Per Mcfe 0.63 0.63 0.69 0.63 General and administrative costs 6,550 6,846 23,629 17,678 Per Mcfe 0.19 0.21 0.18 0.20 Depletion, depreciation and amortization 56,027 51,808 203,093 124,059 Per Mcfe 1.62 1.59 1.56 1.41 EBITDAX 94,096 68,981 284,652 244,991 Discretionary cash flow 86,901 60,980 254,348 230,224 Net income available to common stockholders (14,858) (13,816) (33,328) 48,234 Per common share data (0.27) (0.27) (0.63) 1.11 Per diluted share data (0.27) (0.27) (0.63) 1.09
SUPPLEMENTAL DATA ----------------- (in thousands except per share data) (unaudited) EBITDAX and discretionary cash flow (as defined below) are presented herein because of their wide acceptance as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. EBITDAX and discretionary cash flow should not be considered as alternatives to net cash provided by operating activities, net income (loss) or income (loss) from continuing operations, as defined by Generally Accepted Accounting Principles. EBITDAX and discretionary cash flow should also not be considered as indicators of the Company's financial performance, as alternatives to cash flow, as measures of liquidity or as being comparable to other similarly titled measures of other companies.
FOR THE THREE MONTHS ENDED FOR THE TWELVE MONTHS ENDED DECEMBER 31, DECEMBER 31, -------------------------- --------------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- EBITDAX (1) Net Income (loss) $ (13,668) $ (12,626) $ (28,566) $ 49,821 Exploration 10,752 6,980 32,390 31,313 Depletion, depreciation and amortization 56,027 51,808 203,093 124,059 Impairment of proved properties 19,700 9,423 19,700 9,423 Impairment of unproved properties 883 3,860 9,961 6,974 Stock compensation expense 2,654 1,779 4,608 719 Non-hedge change in fair value of derivatives 17,838 10,163 26,723 (14,323) Interest expense 9,289 8,911 32,398 12,761 Change in fair value of interest rate swap -- (3,083) (226) (4,960) Amortization of deferred financing fees 1,656 (198) 2,438 435 (Gain) Loss on sale of operating assets, net (46) 132 1,685 132 Total benefit (provision) for income taxes (10,989) (7,258) (19,552) 28,637 ---------- ---------- ---------- ---------- EBITDAX $ 94,096 $ 69,891 $ 284,652 $ 244,991 ========== ========== ========== ==========
FOR THE THREE MONTHS ENDED FOR THE TWELVE MONTHS ENDED DECEMBER 31, DECEMBER 31, ---------------------------- ---------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ DISCRETIONARY CASH FLOW(2) Net Income (loss) ........................... $ (13,668) $ (12,626) $ (28,566) $ 49,821 Exploration ................................. 10,752 6,980 32,390 31,313 Depletion, depreciation and amortization .... 56,027 51,808 203,093 124,059 Impairment of proved properties ............. 19,700 9,423 19,700 9,423 Impairment of unproved properties ........... 883 3,860 9,961 6,974 Stock compensation expense .................. 2,654 1,779 4,608 719 Non-hedge change in fair value of derivatives 17,838 10,163 26,723 (14,323) Change in fair value of interest rate swap .. -- (3,083) (226) (4,960) (Gain) Loss on sale of operating assets, net (46) 132 1,685 132 Amortization of financing fees .............. 1,656 (198) 2,438 435 Deferred income tax benefit (provision) ..... (8,895) (7,258) (17,458) 26,631 ------------ ------------ ------------ ------------ Discretionary cash flow .................. $ 86,901 $ 60,980 $ 254,348 $ 230,224 ============ ============ ============ ============
(1) "EBITDAX" represents earnings before exploration; depletion, depreciation and amortization; impairment of unproved properties; stock compensation expense; non-hedge change in fair value of derivatives; interest expense; change in fair value of interest rate swap; amortization of deferred financing fees; and total benefit (provision) for income taxes. (2) Discretionary cash flow equals EBITDAX minus interest expense and current taxes. The tables below provide details about the volumes and prices of all open CPRM commitments, hedge and non-hedge, as of February 19, 2003:
2003 2004 2005 ---------- ---------- ---------- HEDGES GAS NYMEX Price Swaps Sold -- receive fixed price (thousand Mmbtu)(1) .. 31,950 18,300 9,125 Average price, per Mmbtu ........................................ $ 4.01 $ 3.92 $ 3.96 NWPRM Price Swaps Sold -- receive fixed price (thousand Mmbtu)(2) .. -- 10,980 -- Average price, per Mmbtu ........................................ -- $ 3.33 -- CIGRM Price Swaps Sold -- receive fixed price (thousand Mmbtu)(3) .. 3,060 -- -- Average price, per Mmbtu ........................................ $ 3.59 -- -- NYMEX Collars Sold (thousand Mmbtu)(4) ............................. 23,383 16,380 -- Average floor price, per Mmbtu .................................. $ 3.61 $ 3.70 -- Average ceiling price, per Mmbtu ................................ $ 4.29 $ 4.00 -- NWPRM Collars Sold (thousand Mmbtu)(5) ............................. 7,300 -- -- Average floor price, per Mmbtu .................................. $ 3.00 -- -- Average ceiling price, per Mmbtu ................................ $ 3.29 -- -- NYMEX Three-way collars (Mmbtu)(4),(6) ............................. 8,030 3,660 -- Average floor price, per Mmbtu .................................. $ 3.39 $ 4.00 -- Average ceiling price, per Mmbtu ................................ $ 4.73 $ 5.00 -- Three-way average floor price, per Mmbtu ........................ $ 2.22 $ 3.15 -- Basis Swaps(7) NWPRM (thousand Mmbtu) ........................................... 13,430 3,660 -- Average differential price, per Mmbtu ......................... $ 0.67 $ 0.66 -- CIGRM (thousand Mmbtu) ........................................... 3,650 1,830 -- Average differential price, per Mmbtu ......................... $ 0.95 $ 0.81 -- OIL NYMEX Price Swaps Sold -- receive fixed price (Mbbls)(1) ........... 875 1,098 -- Average price, per bbl ........................................... $ 21.80 $ 24.02 -- NYMEX Collars Sold (Mbbls)(4) ...................................... 1,980 -- -- Average floor price, per bbl ..................................... $ 24.45 -- -- Average ceiling price, per bbl ................................... $ 26.45 -- -- NYMEX Three-way collars (Mbbls)(4),(6) ............................. 1,995 1,098 -- Average floor price, per bbl ..................................... $ 23.18 $ 23.83 -- Average ceiling price, per bbl ................................... $ 26.30 $ 26.92 -- Three-way average floor price, per bbl ........................... $ 18.90 $ 19.00 -- NON-HEDGES OIL NYMEX Price Swaps Sold, receive fixed price (Mbbls)(1) ............. 300 -- -- Average price per bbl ............................................ $ 18.86 -- --
- ---------- (1) For any particular NYMEX swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NYMEX Reference Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the NYMEX Reference Price for any settlement period is greater than the swap price for such hedge. (2) For any particular NWPRM swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NWPRM Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the NWPRM Price for any settlement period is greater than the swap price for such hedge. (3) For any particular CIGRM swap sold transaction, the counterparty is required to make a payment to Westport in the event that the CIGRM Price for any settlement period is less than the swap price for such hedge, and Westport is required to make a payment to the counterparty in the event that the CIGRM Price for any settlement period is greater than the swap price for such hedge. (4) For any particular NYMEX collar transaction, the counterparty is required to make a payment to Westport if the average NYMEX Reference Price for the reference period is below the floor price for such transaction, and Westport is required to make payment to the counterparty if the average NYMEX Reference Price is above the ceiling price of such transaction. (5) For any particular NWPRM collar transaction, the counterparty is required to make a payment to Westport if the average NWPRM Price for the reference period is below the floor price for such transaction, and Westport is required to make payment to the counterparty if the average NWPRM Price is above the ceiling price of such transaction. (6) Three way collars are settled as described in footnote (4) above, with the following exception: if the NYMEX Reference Price falls below the three-way floor price, the average floor price is reduced by the amount the NYMEX Reference Price is below the three-way floor price. For example, if the NYMEX Reference Price is $18.00 per bbl during the term of the 2002 three-way collars, then the average floor price would be $22.29 per bbl. (7) For any particular basis swap, the counterparty is required to make a payment to Westport in the event that the difference between the NYMEX Reference Price and the applicable published index (NWPRM or CIGRM) for any settlement period is greater than the swap differential price for such hedge, and Westport is required to make a payment to the counterparty in the event that the difference between the NYMEX Reference Price and the applicable published index (NMPRM or CIGRM) for any settlement period is less than the swap differential price for such hedge. WESTPORT RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands, except share data)
DECEMBER 31, ---------------------------- 2002 2001 ------------ ------------ ASSETS Current Assets: Cash and cash equivalents ........................................................... $ 42,761 $ 27,584 Accounts receivable, net ............................................................ 73,549 61,808 Derivative assets ................................................................... 14,861 7,832 Prepaid expenses and other assets ................................................... 13,358 5,474 ------------ ------------ Total current assets .......................................................... 144,529 102,698 ------------ ------------ Property and equipment, at cost: Oil and natural gas properties, successful efforts method: Proved properties ................................................................. 2,177,656 1,446,331 Unproved properties ............................................................... 104,430 105,539 ------------ ------------ 2,282,086 1,551,870 Less accumulated depletion, depreciation and amortization ........................... (481,396) (280,737) ------------ ------------ Net oil and gas properties .................................................... 1,800,690 1,271,133 ------------ ------------ Building and other office furniture and equipment ................................... 9,686 8,099 Less accumulated depreciation ....................................................... (3,933) (3,028) ------------ ------------ Net building and other office furniture and equipment ........................ 5,753 5,071 ------------ ------------ Other Assets: Long-term derivative assets ......................................................... 14,824 612 Goodwill ............................................................................ 246,712 214,844 Other assets ........................................................................ 21,033 9,858 ------------ ------------ Total other assets ............................................................ 282,569 225,314 ------------ ------------ Total assets .................................................................. $ 2,233,541 $ 1,604,216 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable .................................................................... $ 51,158 $ 47,901 Accrued expenses .................................................................... 39,209 30,294 Ad valorem taxes payable ............................................................ 8,988 6,930 Derivative liabilities .............................................................. 56,156 3,289 Income taxes payable ................................................................ 86 550 Other current liabilities ........................................................... -- 369 ------------ ------------ Total current liabilities ..................................................... 155,597 89,333 ------------ ------------ Long-term debt .......................................................................... 799,358 429,224 Deferred income taxes ................................................................... 124,530 158,005 Long-term derivative liabilities ........................................................ 21,305 5,956 Other liabilities ....................................................................... 745 1,402 ------------ ------------ Total liabilities ............................................................. 1,101,535 683,920 ------------ ------------ Commitments and contingencies (Note 13) Stockholders' equity: 6 1/2% Convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at December 31, 2002 and 2001, respectively ..................................................................... 29 29 Common stock, $.01 par value; 70,000,000 shares authorized; 66,823,830 and 52,092,691 shares issued and outstanding at December 31, 2002 and 2001, respectively ..................................................................... 668 521 Additional paid-in capital .......................................................... 1,150,345 877,960 Treasury stock - at cost; 33,617 and 30,000 shares at December 31, 2002 and 2001, respectively ..................................................................... (469) (408) Retained earnings (accumulated deficit) ............................................. 2 33,330 Accumulated other comprehensive income (loss): Deferred hedge loss, net .......................................................... (18,408) 8,864 Cumulative translation adjustment ................................................. (161) -- ------------ ------------ Total stockholders' equity .................................................... 1,132,006 920,296 ------------ ------------ Total liabilities and stockholders' equity .................................... $ 2,233,541 $ 1,604,216 ============ ============
WESTPORT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share amounts)
FOR THE THREE MONTHS FOR THE YEAR ENDED DECEMBER 31, ENDED DECEMBER 31, ------------------------ ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- Operating revenues: Oil and natural gas sales .......................... $ 133,818 $ 82,873 $ 429,260 $ 317,278 Hedge settlements .................................. (2,785) 3,915 (1,276) 2,091 Commodity price risk management activities: Non-hedge settlements ........................... -- 15,858 822 15,300 Non-hedge change in fair value of derivatives ... (17,838) (10,163) (26,723) 14,323 Gain (loss) on sale of operating assets, net ....... 46 (132) (1,685) (132) ---------- ---------- ---------- ---------- Net revenues .................................... 113,241 92,351 400,398 348,860 ---------- ---------- ---------- ---------- Operating costs and expenses: Lease operating expenses ........................... 21,947 20,545 89,328 55,315 Production taxes ................................... 7,109 4,465 23,954 13,407 Transportation costs ............................... 2,009 1,236 8,791 5,157 Exploration ........................................ 10,752 6,980 32,390 31,313 Depletion, depreciation and amortization ........... 56,027 51,808 203,093 124,059 Impairment of proved properties .................... 19,700 9,423 19,700 9,423 Impairment of unproved properties .................. 883 3,860 9,961 6,974 Stock compensation expense, net .................... 2,654 1,779 4,608 719 General and administrative ......................... 6,550 6,846 23,629 17,678 ---------- ---------- ---------- ---------- Total operating expenses ...................... 127,631 106,942 415,454 264,045 ---------- ---------- ---------- ---------- Operating income (loss) ....................... (14,390) (14,591) (15,056) 84,815 ---------- ---------- ---------- ---------- Other income (expense): Interest expense ................................... (10,945) (8,713) (34,836) (13,196) Interest income .................................... 173 146 546 1,668 Change in interest rate swap fair value ............ -- 3,083 226 4,960 Other .............................................. 505 191 1,002 211 ---------- ---------- ---------- ---------- Income (loss) before income taxes ...................... (24,657) (19,884) (48,118) 78,458 ---------- ---------- ---------- ---------- Provision for income taxes: Current ............................................ 2,094 -- 2,094 (2,006) Deferred ........................................... 8,895 7,258 17,458 (26,631) ---------- ---------- ---------- ---------- Total provision for income taxes .............. 10,989 7,258 19,552 (28,637) ---------- ---------- ---------- ---------- Net income (loss) ...................................... (13,668) (12,626) (28,566) 49,821 Preferred stock dividends .............................. 1,190 1,190 4,762 1,587 ---------- ---------- ---------- ---------- Net income (loss) available to common stockholders ..... $ (14,858) $ (13,816) $ (33,328) $ 48,234 ========== ========== ========== ========== Weighted average number of common shares outstanding: Basic ......................................... 55,644 52,050 53,007 43,408 ========== ========== ========== ========== Diluted ....................................... 55,644 52,050 53,007 44,168 ========== ========== ========== ========== Net income (loss) per common share: Basic ......................................... $ (.27) $ (.27) $ (.63) $ 1.11 ========== ========== ========== ========== Diluted ....................................... $ (.27) $ (.27) $ (.63) $ 1.09 ========== ========== ========== ==========
WESTPORT RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------- 2002 2001 2000 ---------- ---------- ---------- Cash flows from operating activities: Net income (loss) .................................................. $ (28,566) $ 49,821 $ 43,536 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization ......................... 203,093 124,059 64,856 Exploratory dry hole costs ....................................... 19,546 19,273 6,020 Impairment of proved properties .................................. 19,700 9,423 2,911 Impairment of unproved properties ................................ 9,961 6,974 5,124 Deferred income taxes ............................................ (17,707) 26,631 23,049 Director retainers settled for stock ............................. 20 -- 50 Stock compensation expense ....................................... 4,608 719 2,156 Change in derivative fair value .................................. 27,475 (19,283) -- Amortization of financing fees ................................... 2,438 435 -- Capitalized interest ............................................. (45) -- -- Loss (gain) on sale of assets .................................... 1,685 132 (3,130) Changes in assets and liabilities, net of effects of acquisitions: Decrease (increase) in accounts receivable .................... (2,909) 10,126 (28,678) Decrease (increase) in prepaid expenses ....................... (5,031) 1,051 (1,139) Decrease in net derivative liabilities ........................ (10,388) (18,285) -- Increase (decrease) in accounts payable ....................... (6,573) (6,240) 17,930 Increase (decrease) in ad valorem taxes payable ............... (851) (1,130) 2,183 Increase (decrease) in income taxes payable ................... (477) 301 375 Increase (decrease) in accrued expenses ....................... 8,105 (8,474) 9,622 Decrease in other liabilities ................................. (887) (260) (1,436) ---------- ---------- ---------- Net cash provided by operating activities .............................. 223,197 195,273 143,429 ---------- ---------- ---------- Cash flows from investing activities: Additions to property and equipment ................................ (147,612) (187,925) (102,229) Proceeds from sales of assets ...................................... 13,311 5,536 6,259 Merger with EPGC ................................................... -- -- (42,403) Other acquisitions ................................................. (679,890) (6,319) (1,454) Other .............................................................. 28 22 (342) ---------- ---------- ---------- Net cash used in investing activities .................................. (814,163) (188,686) (140,169) ---------- ---------- ---------- Cash flows from financing activities: Proceeds from issuance of common stock, net ........................ 267,787 576 104,052 Repurchase of common stock ......................................... (61) (408) -- Proceeds from issuance of long-term debt ........................... 639,000 590,000 50,000 Repayment of long-term debt ........................................ (285,000) (577,585) (156,633) Preferred stock dividend ........................................... (4,762) (1,587) -- Gain on interest rate swap cancellation ............................ 3,705 -- -- Financing fees ..................................................... (14,273) (10,153) -- ---------- ---------- ---------- Net cash provided by (used in) financing activities .................... 606,396 843 (2,581) ---------- ---------- ---------- Net increase in cash and cash equivalents .............................. 15,430 7,430 679 Effect of exchange rate changes on cash and cash equivalents ........... (253) -- -- Cash and cash equivalents, beginning of year ........................... 27,584 20,154 19,475 ---------- ---------- ---------- Cash and cash equivalents, end of year ................................. $ 42,761 $ 27,584 $ 20,154 ========== ========== ========== Supplemental cash flow information: Cash paid for interest ............................................. $ 37,426 $ 14,065 $ 10,649 ========== ========== ========== Cash paid for income taxes ......................................... $ 44 $ 1,700 $ 300 ========== ========== ========== Supplemental schedule of non-cash investing and financing activities: Common stock and stock options issued in connection with the Belco and EPGC mergers, respectively ............................. $ -- $ 349,919 $ 165,356 ========== ========== ========== Liabilities and preferred stock assumed in connection with the Belco and EPGC mergers, respectively ............................. $ -- $ 662,089 $ 1,850 ========== ========== ========== EPGC merger expenses paid by parent .............................. $ -- $ -- $ 2,895 ========== ========== ==========
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS. (a) Financial Statements of business acquired. None. (b) Pro Forma Financial Information. None. (c) Exhibits. None. [SIGNATURE PAGE FOLLOWS] SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. WESTPORT RESOURCES CORPORATION Date: February 27, 2003 By: /s/ LON MCCAIN -------------------------------------- Name: Lon McCain Title: Vice President, Chief Financial Officer and Treasurer -----END PRIVACY-ENHANCED MESSAGE-----