-----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, T7+mSG/BiZFhIpqzIM9x4061ZVULI8TcwJBjwRtbI/R3gTLE9CShS/hKjm5qnpEb /BPPpvZkG+qdKav6RK/bhw== 0000950134-03-010913.txt : 20030805 0000950134-03-010913.hdr.sgml : 20030805 20030804205741 ACCESSION NUMBER: 0000950134-03-010913 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20030804 ITEM INFORMATION: FILED AS OF DATE: 20030805 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: 03822073 BUSINESS ADDRESS: STREET 1: 1670 BROADWAY STREET 2: SUITE 2800 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 303-573-5404 MAIL ADDRESS: STREET 1: 1670 BROADWAY STREET 2: SUITE 2800 CITY: DENVER STATE: CO ZIP: 80202 FORMER COMPANY: FORMER CONFORMED NAME: BELCO OIL & GAS CORP DATE OF NAME CHANGE: 19960207 8-K 1 d07943e8vk.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): AUGUST 4, 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 12. RESULTS OF OPERATIONS AND FINANCIAL CONDITION On August 4, 2003, Westport Resources Corporation, a Nevada corporation, issued a press release announcing its financial and operating results for the second quarter ended June 30, 2003. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K. [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: August 4, 2003 By: /s/ LON MCCAIN ------------------------------- Name: Lon McCain Title: Vice President, Chief Financial Officer and Treasurer EXHIBIT INDEX
EXHIBIT NUMBER EXHIBIT - ------ ------- 99.1* Press release dated August 4, 2003 entitled "Westport Reports Financial Results and Record Production in Second Quarter 2003."
- ---------- *Filed herewith. EX-99.1 3 d07943exv99w1.txt PRESS RELEASE EXHIBIT 99.1 [WESTPORT RESOURCES CORPORATION LOGO] WESTPORT RESOURCES CORPORATION 1670 BROADWAY, SUITE 2800 DENVER, CO 80202 WESTPORT REPORTS FINANCIAL RESULTS AND RECORD PRODUCTION IN SECOND QUARTER 2003 Denver, Colorado - August 4, 2003 - Westport Resources Corporation (NYSE: WRC) today announced increases in production, net income, EBITDAX and discretionary cash flow for the quarter and six months ended June 30, 2003, compared to the corresponding periods in 2002. Net income available to common stockholders was approximately $13.2 million, or $0.20 per basic share ($0.19 per fully diluted share), in the second quarter of 2003, compared to net income available to common stockholders of approximately $1.2 million, or $0.02 per basic share ($0.02 per fully diluted share), in the second quarter of 2002. For the six months ended June 30, 2003, net income available to common stockholders was approximately $32.5 million, or $0.49 per basic share ($0.48 per fully diluted share), compared to a net loss of approximately $19.4 million, or $0.37 per basic share ($0.37 per fully diluted share), for the same period in 2002. Net cash provided by operating activities for the second quarter and first six months of 2003 achieved record levels for Westport of approximately $101.1 million and $196.4 million, respectively, compared to $39.7 million and $80.8 million recorded during the corresponding periods of 2002. Discretionary cash flow also achieved record levels of approximately $112.4 million during the second quarter of 2003 and $224.1 million during the first half of 2003, compared to $67.9 million and $107.3 million, respectively, achieved during the corresponding periods of 2002. EBITDAX for the second quarter and first six months of 2003 was approximately $125.2 million and $253.0 million, respectively, compared to $75.6 million and $123.1 million recorded during the corresponding periods of 2002. EBITDAX and discretionary cash flow are financial measures that are calculated on the basis of methodologies other than Generally Accepted Accounting Principles ("GAAP"). EBITDAX and discretionary cash flow are presented herein because of their wide acceptance as financial indicators of a company's ability to internally generate funds for exploration, development and acquisition activities and to service or incur debt. For a definition, detailed summary and reconciliation of each measure to the most comparable GAAP measure, please refer to the section entitled "Reconciliation of Non-GAAP Financial Measures" included in this release. "During the second quarter of 2003, we increased our production 85 Mmcfe/d year over year and nearly 10 Mmcfe/d from the first quarter of this year," commented Don Wolf, Chairman and Chief Executive Officer of Westport. "As a result of higher commodity prices and cash flows, we expanded the 2003 capital spending program from $230 million to $270 million. The additional expenditures will be allocated primarily to the development of our Utah properties, our Southeast Texas drilling program and development costs related to recent discoveries in the Gulf of Mexico." PRODUCTION AND COMMODITY PRICES Average daily gas equivalent production for the second quarter of 2003 increased approximately 23% to a record 449 Mmcfe/d, compared to 364 Mmcfe/d in the second quarter of 2002, and increased 2%, compared to 440 Mmcfe/d in the first quarter of 2003. Approximately 72% of second quarter 2003 production was natural gas. For the six months ended June 30, 2003, average daily oil and gas production increased 26% to approximately 445 Mmcfe/d, compared to 354 Mmcfe/d for the corresponding prior year period. Realized commodity prices for the second quarter of 2003 averaged approximately $26.90 per barrel of oil and $4.90 per Mcf of gas before the effect of hedge settlements and approximately $24.95 per barrel of oil and $4.23 per Mcf of gas after such effect. For the same period in 2002, realized commodity prices averaged approximately $23.88 per barrel of oil and $3.07 per Mcf of gas before the effect of hedge settlements and approximately $23.93 per barrel of oil and $3.04 per Mcf of gas after such effect. During the first six months of 2003, realized commodity prices averaged approximately $29.33 per barrel of oil and $5.25 per Mcf of gas before the effect of hedge settlements and approximately $25.79 per barrel of oil and $4.37 per Mcf of gas after such effect. For the corresponding period in 2002, realized commodity prices averaged approximately $21.30 per barrel of oil and $2.64 per Mcf of gas before the effect of hedge settlements and approximately $21.77 per barrel of oil and $2.68 per Mcf of gas after such effect. OPERATING RESULTS In the second quarter of 2003, Westport drilled 91 development wells, 98% of which were successful, and six exploration wells, 50% of which were successful. As of June 30, 2003, 23 development wells and nine exploration wells were either being drilled or completed. The following table summarizes the second quarter 2003 drilling activity for each of Westport's Divisions:
Gulf of Mexico Northern Division Western Division Southern Division Division Company Total ----------------- ----------------- ----------------- ----------------- ----------------- Total Success Total Success Total Success Total Success Total Success Drilled Rate Drilled Rate Drilled Rate Drilled Rate Drilled Rate ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- Wells drilled during second quarter 2003 Development wells 29 97% 27 100% 34 97% 1 100% 91 98% Exploration wells 1 0% 1 100% -- N/A 4 50% 6 50% --- --- --- --- --- Total 30 28 34 5 97 Wells in progress as of June 30, 2003 Development wells 4 4 15 -- 23 Exploration wells 4 -- 4 1 9 --- --- --- --- --- Total 8 4 19 1 32
NORTHERN DIVISION Westport's net daily production for its Northern Division averaged approximately 109 Mmcfe/d during the second quarter of 2003, representing approximately a 4% decrease from 113 Mmcfe/d reported in the second quarter of 2002. Adjusting for asset sales subsequent to the second quarter of 2002, production was approximately flat with year-over-year growth. During the second quarter of 2003, the Company participated in the drilling of 29 development wells, 97% of which were successful, and one unsuccessful exploration well in the Northern Division. Westport continued its successful horizontal drilling program in the Williston Basin, drilling seven successful development wells during the second quarter, with one exploratory well drilling at the end of the quarter. The net daily production from the Basin for the quarter averaged approximately 47 Mmcfe/d, representing approximately 43% of the Northern Division's net production. In the Powder River Basin, Westport drilled 11 successful Wyodak coalbed methane development wells during the quarter. Current production net to Westport is approximately 17 Mmcfe/d. The Company plans to drill 35 to 40 additional coalbed methane wells during the remainder of 2003 in this Division. The Company increased its activity in the Greater Green River Basin, drilling and completing five development wells during the quarter with an average initial production rate of approximately 1.7 Mmcfe/d. At the end of the quarter, the Company was drilling or completing three exploration wells and three additional development wells. Westport plans to drill 10 to 15 additional wells in this area during the remainder of the year. WESTERN DIVISION Westport's net daily production for its Western Division averaged approximately 75 Mmcfe/d during the second quarter of 2003, representing approximately a 12% increase from 67 Mmcfe/d in the first quarter of 2003. During the second quarter of 2003, Westport drilled nine development wells targeting the Wasatch formations, 15 development wells targeting the Wasatch and Upper Mesa Verde formations, and three development wells and one exploration well targeting the deeper Lower Mesa Verde and Mancos horizons. All of these wells were successfully completed, with 25 of the wells commencing production during the second quarter and the remaining three wells commencing production in early July. As of June 30, 2003, Westport was drilling or completing four additional development wells in the Western Division. Westport currently has five operated rigs drilling on its Utah properties, with two of the rigs committed to drilling deeper objectives. In addition, Westport is a participant in drilling activity conducted by a third party operating approximately two drilling rigs, with an average working interest of 33%. The Company expects to drill an additional 40 to 45 wells in the Western Division during the remainder of the year. SOUTHERN DIVISION Westport's net daily production for its Southern Division averaged approximately 153 Mmcfe/d during the second quarter of 2003, representing approximately a 16% increase from 132 Mmcfe/d reported in the second quarter of 2002. During the second quarter of 2003, Westport drilled 34 development wells, of which 97% were successful. Westport's Southeast Texas properties acquired in September 2002 are currently producing approximately 40 Mmcfe/d compared to 28 Mmcfe/d at the time of the acquisition. The Company is currently completing one exploration well and one development well and drilling two exploration wells in this area. Westport expects to drill between six and eight additional wells in this area during the second half of 2003. Within the Westport operated Raywood 120 square mile 3-D shoot, the Company has identified 15 additional exploratory prospect leads. Within the non-operated 101 square mile Willow Creek 3-D shoot, the Company has identified eight to 10 exploration leads. During the second quarter of 2003, Westport participated in an additional shoot covering 91 square miles, which is currently being processed. In the Permian Basin, Westport drilled 12 development wells during the second quarter of 2003. All of these wells were successful and commenced production in the second quarter. At the end of the second quarter, Westport was drilling or completing four development wells and expects to drill an additional 8 to twelve development wells during the second half of the year in this basin. Net daily production from the Permian Basin averaged approximately 41 Mmcfe/d for the second quarter of 2003. Westport continued its active development program in various fields located in North Louisiana. During the second quarter, Westport drilled 14 development wells with a 93% success rate and as of June 30, 2003, the Company was drilling or completing nine additional development wells. Net daily production from North Louisiana averaged approximately 28 Mmcfe/d for the second quarter of 2003. The Company expects to drill an additional 20 to 24 wells in North Louisiana in the second half of 2003. Westport drilled and commenced production from two extension wells in the Spaulding discovery located in McMullen County, Texas, during the second quarter of 2003. The new field is currently producing approximately 13 Mmcfe/d gross and the Company expects to drill an additional one to two development wells in this area during the second half of 2003. Westport holds a 35% working interest in this property. GULF OF MEXICO DIVISION Westport's net daily production for its Gulf of Mexico Division averaged approximately 113 Mmcfe/d during the second quarter of 2003, representing a 5% decrease from 119 Mmcfe/d reported in the second quarter of 2002. During the second quarter of 2003, Westport drilled a successful development well in Eugene Island Block 273 and a successful exploration well in each of West Cameron Block 73 and Galveston Blocks 351/352. The Company drilled an unsuccessful exploration well in each of West Cameron 181 and Atwater 7. The exploration well in West Cameron Block 73 encountered more than 250 feet of net gas pay. Westport owns a 30% working interest in this Newfield operated prospect and first production is expected from the field in early 2004. In Galveston Blocks 351/352, Westport operates and owns a 67% working interest. The Company plans to install additional facilities and add production from the second of two exploration wells by the end of the third quarter of 2003. In South Timbalier Blocks 315/316, Westport installed the platform, pipelines and facilities during the second quarter of 2003. A drilling rig is mobilizing on the platform and the Company intends to tieback and complete the three existing wells during the second half of 2003. Westport expects production to commence from the first well by the end of the third quarter of 2003, with all three wells producing by year-end. Westport operates this field and holds a 40% working interest. The Company also completed installation of Ship Shoal Block 94 production platform, pipeline and facilities during the second quarter of 2003. Production from this block commenced in July with an initial rate of approximately 25 Mmcfe/d. Westport operates this Block and holds a 60% working interest. COMMODITY PRICE RISK MANAGEMENT For the three months ended June 30, 2003, Westport recorded hedge settlement charges of approximately $23.4 million, non-hedge settlement gains of $0.7 million and non-hedge non-cash change in fair value of derivative gains of $0.9 million. For the corresponding period in 2002, Westport recorded hedge settlement losses of $0.6 million, non-hedge settlement losses of $0.3 million and non-hedge non-cash change in fair value of derivative gains of $1.0 million. For the first half of 2003, Westport recorded hedge settlement charges of approximately $63.9 million, non-hedge settlement gains of $0.7 million and non-hedge non-cash change in fair value of derivatives gains of $3.2 million. For the corresponding period in 2002, Westport recorded hedge settlement gains of $3.4 million, non-hedge settlement gains of $0.8 million and non-hedge non-cash change in fair value of derivatives losses of $8.2 million. For a detailed summary of commodity price risk management contracts, please refer to the commodity price risk management table included in this release. 2003 AND 2004 GUIDANCE COMMENT The company believes that its 2003 results will be within the guidance ranges previously disclosed. Westport believes that, based upon a preliminary analysis of its expected 2004 operating results, its 2004 production will increase 6% to 10% from the levels achieved in 2003. CONFERENCE CALL Westport will host a telephone conference call on Tuesday August 5, 2003, at 11:00 a.m. EDT to discuss financial and operational results for the second quarter of 2003. Please call 800-240-2134 (US/Canada) or 303-205-0033 (International) to be connected to the call. A digitized replay will also be available for two weeks following the live broadcast at 800-405-2236 (US/Canada) or 303-590-3000 (International) and can be accessed by using the passcode 547366#. In addition, the conference call will be available live on the Internet from the Investor Relations-Webcast Presentation tab on Westport's website at www.westportresourcescorp.com. To listen to the live call, please go to the website at least 15 minutes early to register, download and install any necessary audio software. For those who cannot listen to the live broadcast, a replay will be available shortly after the call and archived on the Company's website. SUMMARY DATA (in thousands, except per unit data)
FOR THE THREE MONTHS FOR THE SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, ------------------------------ ---------------------------- 2003 2002 2003 2002 ------------ ------------ ------------ ----------- Production Oil (Mbbls) .............................. 1,941 2,092 3,987 3,897 Natural gas (Mmcf) ....................... 29,235 20,551 56,554 40,628 Mmcfe .................................... 40,881 33,103 80,476 64,010 Average Daily Production Oil (Mbbls/d) ............................ 21.3 23.0 22.0 21.5 Natural gas (Mmcf/d) ..................... 321.3 225.8 312.5 224.5 Mmcfe/d .................................. 449.2 363.8 444.6 353.6 Average Prices Oil (per bbl) ............................ $ 26.90 $ 23.88 $ 29.33 $ 21.30 Natural gas (per Mcf) .................... 4.90 3.07 5.25 2.64 Price per Mcfe ........................... 4.78 3.41 5.14 2.97 Hedging effect (per bbl) ..................... (1.95) 0.05 (3.54) 0.47 Hedging effect (per Mcf) ..................... (0.67) (0.03) (0.88) 0.04 Hedging effect (per Mcfe) .................... (0.57) (0.02) (0.79) 0.05 Oil and natural gas sales .................... $ 195,584 $ 113,007 $ 414,003 $ 190,019 Lease operating expense ...................... 26,032 24,229 52,368 43,904 Per Mcfe ................................. 0.64 0.73 0.65 0.69 Production taxes ............................. 11,364 5,771 24,422 11,636 Per Mcfe ................................. 0.28 0.17 0.30 0.18 Transportation costs ......................... 3,354 1,951 7,378 4,603 Per Mcfe ................................. 0.08 0.06 0.09 0.07 General and administrative costs ............. 7,543 5,495 14,771 11,429 Per Mcfe ................................. 0.18 0.17 0.18 0.18 Depletion, depreciation and amortization ..... 67,036 51,791 128,101 99,380 Per Mcfe ................................. 1.64 1.56 1.59 1.55
RECONCILIATION OF NON-GAAP FINANCIAL MEASURES (in thousands) 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 and net income (loss) or income (loss) from continuing operations, as defined by GAAP. 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. The following sets forth a reconciliation of net cash provided by operating activities to EBITDAX and discretionary cash flow:
FOR THE THREE MONTHS FOR THE SIX MONTHS ENDED ENDED JUNE 30, JUNE 30, ------------------------ ------------------------ 2003 2002 2003 2002 --------- --------- --------- --------- EBITDAX (1) Net cash provided by operating activities $ 101,130 39,731 196,416 80,831 Adjustments: Interest expense 12,792 7,700 28,852 15,809 Loss on debt retirement 920 -- 920 -- Changes in other assets and liabilities 6,755 25,549 16,040 18,508 Exploration costs 3,588 2,686 10,743 8,247 Certain non-cash items -- (20) -- (246) --------- --------- --------- --------- EBITDAX $ 125,185 $ 75,646 $ 252,971 $ 123,149 ========= ========= ========= ========= DISCRETIONARY CASH FLOW (2) Net cash provided by operating activities 101,130 39,731 196,416 80,831 Adjustments: Loss on debt retirement 920 -- 920 -- Changes in other assets and liabilities 6,755 25,549 16,040 18,508 Exploration costs 3,588 2,686 10,743 8,247 Certain non-cash items -- (20) -- (246) --------- --------- --------- --------- Discretionary cash flow $ 112,393 $ 67,946 $ 224,119 $ 107,340 ========= ========= ========= =========
- ---------- (1) "EBITDAX" is a non-GAAP financial measure equal to net cash provided by operating activities, the most directly comparable GAAP financial measure, adjusted for interest expense, loss on debt retirement, changes in other assets and liabilities, exploration costs and certain non-cash items. (2) "Discretionary cash flow" is a non-GAAP financial measure equal to net cash provided by operating activities, the most directly comparable GAAP financial measure, adjusted for loss on debt retirement, changes in other assets and liabilities, exploration costs and certain non-cash items. COMMODITY PRICE RISK MANAGEMENT The summary tables below provide details as of July 31, 2003 regarding the volumes and prices of all open commodity price risk management contracts, including hedge and non-hedge commitments, for the third and fourth quarters of 2003 and for all of 2004 and 2005.
2003 2004 2005 ---------- ---------- ---------- (THIRD AND FOURTH ----------------- QUARTERS) --------- HEDGES GAS NYMEX Price Swaps Sold -- receive fixed price (thousand Mmbtu)(1) ... 16,196 21,960 16,425 Average price, per Mmbtu .......................................... $ 4.01 $ 4.11 $ 4.35 NWPRM Price Swaps Sold -- receive fixed price (thousand Mmbtu)(2) ... -- 10,980 -- Average price, per Mmbtu .......................................... -- $ 3.33 -- CIG Price Swaps Sold -- receive fixed price (thousand Mmbtu)(3) ..... 1,840 -- -- Average price, per Mmbtu .......................................... $ 3.59 -- -- NYMEX Collars Sold (thousand Mmbtu)(4) .............................. 11,740 16,380 3,650 Average floor price, per Mmbtu .................................... $ 3.61 $ 3.70 $ 4.00 Average ceiling price, per Mmbtu .................................. $ 4.29 $ 4.00 $ 5.07 NWPRM Collars Sold (thousand Mmbtu)(5) .............................. 3,680 -- -- Average floor price, per Mmbtu ................................... $ 3.00 -- -- Average ceiling price, per Mmbtu ................................. $ 3.29 -- -- NYMEX Three-way collars (Mmbtu)(4),(6) .............................. 4,048 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 Versus NYMEX(7) NWPRM (thousand Mmbtu) ............................................ 6,748 3,660 3,650 Average differential price, per Mmbtu .......................... $ 0.67 $ 0.66 $ 0.78 CIG (thousand Mmbtu) .............................................. 1,840 1,830 -- Average differential price, per Mmbtu .......................... $ 0.95 $ 0.81 -- OIL NYMEX Price Swaps Sold -- receive fixed price (Mbbls)(1) ............ 304 2,196 -- Average price, per bbl ............................................ $ 21.39 $ 24.61 -- NYMEX Collars Sold (Mbbls)(4) ....................................... 990 -- -- Average floor price, per bbl ...................................... $ 24.45 -- -- Average ceiling price, per bbl .................................... $ 26.45 -- -- NYMEX Three-way collars (Mbbls)(4),(6) .............................. 1,002 1,098 365 Average floor price, per bbl ...................................... $ 23.17 $ 23.83 $ 24.25 Average ceiling price, per bbl .................................... $ 26.30 $ 26.92 $ 28.00 Three-way average floor price, per bbl ............................ $ 18.90 $ 19.00 $ 20.90 NON-HEDGES GAS Basis swaps, index versus index(8) NWPRM versus CIG (Mmbtu) ......................................... 4,920 -- -- Average differential price, per Mmbtu ........................ $ 0.42 -- -- OIL NYMEX Price Swaps Sold, receive fixed price (Mbbls)(1) .............. 150 -- -- Average price per bbl ............................................. $ 18.86 -- --
- ---------- (1) For any particular New York Mercantile Exchange ("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 Northwest Pipeline Rocky Mountain Index ("NWPRM") swap sold transaction, the counterparty is required to make a payment to Westport in the event that the NWPRM Index 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 Index Price for any settlement period is greater than the swap price for such hedge. (3) For any particular Colorado Interstate Gas ("CIG") swap sold transaction, the counterparty is required to make a payment to Westport in the event that the CIG Index 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 CIG Index 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 Index 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 Index 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 2003 three-way collars, then the average floor price would be $22.27 per bbl. (7) For any particular basis swap versus NYMEX, 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 CIG) 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 (NWPRM or CIG) for any settlement period is less than the swap differential price for such hedge. (8) These basis swaps are based on the differences in two indices not versus NYMEX. The counterparty is required to make a payment to Westport in the event that CIG plus the swap differential price exceeds NWPRM for any settlement period, and Westport is required to make a payment to the counterparty in the event that CIG plus the swap differential price is less than NWPRM for any settlement period. CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31, 2003 2002 ------------ ------------ (UNAUDITED) ASSETS Current Assets: Cash and cash equivalents ...................................................... $ 65,865 $ 42,761 Accounts receivable, net ....................................................... 81,520 73,549 Derivative assets .............................................................. 8,401 14,861 Prepaid expenses ............................................................... 14,771 13,358 ------------ ------------ Total current assets ......................................................... 170,557 144,529 ------------ ------------ Property and equipment, at cost: Oil and natural gas properties, successful efforts method: Proved properties ............................................................ 2,269,540 2,138,471 Unproved properties .......................................................... 94,944 104,430 ------------ ------------ 2,364,484 2,242,901 Less accumulated depletion, depreciation and amortization ...................... (592,905) (481,396) ------------ ------------ Net oil and gas properties ................................................... 1,771,579 1,761,505 ------------ ------------ Field services assets .......................................................... 39,198 39,185 Less accumulated depreciation .................................................. (560) -- ------------ ------------ Net field services assets .................................................... 38,638 39,185 ------------ ------------ Building and other office furniture and equipment .............................. 10,274 9,686 Less accumulated depreciation .................................................. (4,246) (3,933) ------------ ------------ Net building and other office furniture and equipment ........................ 6,028 5,753 ------------ ------------ Other assets: Long-term derivative assets .................................................... 17,792 14,824 Goodwill ....................................................................... 244,647 246,712 Other assets ................................................................... 19,697 21,033 ------------ ------------ Total other assets ........................................................... 282,136 282,569 ------------ ------------ Total assets ................................................................. $ 2,268,938 $ 2,233,541 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts payable ............................................................... $ 48,572 $ 51,158 Accrued expenses ............................................................... 41,484 39,209 Ad valorem taxes payable ....................................................... 15,217 8,988 Derivative liabilities ......................................................... 98,173 56,156 Income taxes payable ........................................................... 83 86 Current asset retirement obligation ............................................ 7,960 -- ------------ ------------ Total current liabilities .................................................... 211,489 155,597 Long-term debt ..................................................................... 731,879 799,358 Deferred income taxes .............................................................. 114,672 124,530 Long term derivative liabilities ................................................... 42,632 21,305 Long term asset retirement obligation .............................................. 50,143 745 ------------ ------------ Total liabilities ............................................................ 1,150,815 1,101,535 ------------ ------------ Stockholders' equity: 6 1/2% convertible preferred stock, $.01 par value; 10,000,000 shares authorized; 2,930,000 issued and outstanding at June 30, 2003 and December 31, 2002, respectively ....................................................... 29 29 Common stock, $0.01 par value; 100,000,000 authorized; 67,237,667 and 66,823,830 shares issued and outstanding at June 30, 2003 and, December 31, 2002, respectively ................................................................ 672 668 Additional paid-in capital ..................................................... 1,156,031 1,150,345 Treasury stock-at cost; 35,681 and 33,617 shares at June 30, 2003 and December 31, 2002, respectively ............................................. (512) (469) Retained earnings .............................................................. 32,469 2 Accumulated other comprehensive income Deferred hedge loss, net .................................................... (70,405) (18,408) Cumulative translation adjustment ........................................... (161) (161) ------------ ------------ Total stockholders' equity .................................................. 1,118,123 1,132,006 ------------ ------------ Total liabilities and stockholders' equity ..................................... $ 2,268,938 $ 2,233,541 ============ ============
CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
FOR THE THREE MONTHS FOR THE SIX MONTHS ENDED JUNE 30, ENDED JUNE 30, ------------------------- ------------------------- 2003 2002 2003 2002 --------- --------- --------- --------- Operating revenues: Oil and natural gas sales ................................ $ 195,584 $ 113,007 $ 414,003 $ 190,019 Hedge settlements ........................................ (23,439) (577) (63,885) 3,358 Gathering income ......................................... 783 -- 1,992 -- Commodity price risk management activities: Non-hedge settlements ................................ 723 (262) 723 822 Non-hedge change in fair value of derivatives ........ 902 1,031 3,222 (8,222) Gain (loss) on sale of operating assets, net ............. 6,074 (1,868) 6,466 (1,868) --------- --------- --------- --------- Net revenues ...................................... 180,627 111,331 362,521 184,109 --------- --------- --------- --------- Operating costs and expenses: Lease operating expenses ................................. 26,032 24,229 52,368 43,904 Production taxes ......................................... 11,364 5,771 24,422 11,636 Transportation costs ..................................... 3,354 1,951 7,378 4,603 Gathering expenses ....................................... 552 -- 1,648 -- Exploration .............................................. 13,624 7,700 25,671 18,042 Depletion, depreciation and amortization ................. 67,036 51,791 128,101 99,380 Impairment of proved properties .......................... 977 -- 977 -- Impairment of unproved properties ........................ 11,693 5,331 15,173 6,290 Stock compensation expense, net .......................... 2,153 (1,787) 2,150 94 General and administrative ............................... 7,543 5,495 14,771 11,429 --------- --------- --------- --------- Total operating expenses .......................... 144,328 100,481 272,659 195,378 --------- --------- --------- --------- Operating income (loss) ........................... 36,299 10,850 89,862 (11,269) Other income (expense): Interest expense ......................................... (13,058) (7,978) (29,400) (16,349) Interest income .......................................... 180 121 381 201 Change in fair value of interest rate swap ............... -- -- -- 226 Loss on debt retirement .................................. (920) -- (920) -- Other .................................................... 188 803 333 321 --------- --------- --------- --------- Income (loss) before income taxes ............................ 22,689 3,796 60,256 (26,870) --------- --------- --------- --------- Benefit (provision) for income taxes: Current ................................................. -- -- -- -- Deferred ................................................ (8,281) (1,386) (21,993) 9,807 --------- --------- --------- --------- Total benefit (provision) for income taxes ........ (8,281) (1,386) (21,993) 9,807 --------- --------- --------- --------- Net income (loss) before cumulative effect of change in accounting principle ................................. 14,408 2,410 38,263 (17,063) Cumulative effect of change in accounting principle (net of tax effect of $1,962) ................................ -- -- (3,414) -- --------- --------- --------- --------- Net income (loss) ............................................ 14,408 2,410 34,849 (17,063) Preferred stock dividends .................................... (1,191) (1,191) (2,382) (2,381) --------- --------- --------- --------- Net income (loss) available to common stockholders ........... $ 13,217 $ 1,219 $ 32,467 $ (19,444) ========= ========= ========= ========= Weighted average number of common shares outstanding: Basic ................................................... 67,052 52,128 66,935 52,104 ========= ========= ========= ========= Diluted ................................................. 67,942 52,760 67,787 52,104 ========= ========= ========= ========= Net income (loss) per common share: Basic: Net income (loss) before cumulative effect of change in accounting principle ................................. $ .20 $ .02 $ .54 $ (.37) Cumulative effect of change in accounting principle ..... -- -- (.05) -- --------- --------- --------- --------- Net income (loss) available to common stockholders ... $ .20 $ .02 $ .49 $ (.37) ========= ========= ========= ========= Diluted: Net income (loss) before cumulative effect of change in accounting principle ................................. $ .19 $ .02 $ .53 $ (.37) Cumulative effect of change in accounting principle ..... -- -- (.05) -- --------- --------- --------- --------- Net income (loss) available to common stockholders ... $ .19 $ .02 $ .48 $ (.37) ========= ========= ========= =========
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)
FOR THE SIX MONTHS ENDED JUNE 30, --------------------------------- 2003 2002 ------------- ------------- Cash flows from operating activities: Net income (loss) ........................................................... $ 34,849 $ (17,063) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization .................................. 128,101 99,380 Exploratory dry hole costs ................................................ 14,928 9,795 Impairment of proved properties ........................................... 977 -- Impairment of unproved properties ......................................... 15,173 6,290 Deferred income taxes ..................................................... 21,993 (9,807) Director retainers settled for stock ...................................... 11 20 Stock compensation expense ................................................ 2,150 94 Change in fair value of derivatives ....................................... 3,514 7,996 Amortization of derivative liabilities .................................... (9,625) (5,018) Amortization of deferred financing fees ................................... 548 540 Gain on sale of operating assets, net ..................................... (6,466) 1,868 Cumulative change in accounting principle, net of tax ..................... 3,414 -- Changes in assets and liabilities, net of effects of acquisitions: Decrease (increase) in accounts receivable ............................. (15,423) 5,023 Increase in prepaid expenses ........................................... (1,039) (2,992) Decrease in accounts payable ........................................... (2,511) (17,889) Increase in ad valorem taxes payable ................................... 6,228 502 Decrease in income taxes payable ....................................... (3) (44) Increase in accrued expenses ........................................... 59 2,582 Decrease in other liabilities .......................................... (462) (446) --------- --------- Net cash provided by operating activities ....................................... 196,416 80,831 --------- --------- Cash flows from investing activities: Additions to property and equipment ....................................... (115,626) (71,769) Proceeds from sales of assets ............................................. 13,281 7,790 Acquisitions of oil and gas properties and purchase price adjustments ..... 3,557 (42,303) Other ..................................................................... -- (52) --------- --------- Net cash used in investing activities ........................................... (98,788) (106,334) --------- --------- Cash flows from financing activities: Proceeds from issuance of common stock .................................... 3,530 1,071 Proceeds from issuance of long-term debt .................................. 151,875 55,000 Repayment of long term debt ............................................... (226,311) -- Preferred stock dividends paid ............................................ (2,381) (2,381) Repurchase of common stock ................................................ (43) (61) Loss on retirement of debt ................................................ (920) Financing fees ............................................................ (274) (271) --------- --------- Net cash provided by (used in) financing activities ............................. (74,524) 53,358 --------- --------- Net increase in cash and cash equivalents ....................................... 23,104 27,855 Cash and cash equivalents, beginning of period .................................. 42,761 27,584 --------- --------- Cash and cash equivalents, end of period ........................................ $ 65,865 $ 55,439 ========= ========= Supplemental cash flow information: Cash paid for interest .................................................... $ 33,182 $ 17,664 ========= ========= Cash paid for income taxes ................................................ $ 3 $ 44 ========= =========
Westport is an independent energy company engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the Rocky Mountains, Permian Basin/Mid-Continent, the Gulf Coast and offshore Gulf of Mexico. Contact information: Lon McCain or Jonathan Bloomfield at (303) 573-5404. FORWARD - LOOKING STATEMENTS This release 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, estimated expenses, estimated prices and basis differentials, cash flow and capital expenditures, projected drilling and development activity, projected production, and projected property sales. 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 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 release. -----END PRIVACY-ENHANCED MESSAGE-----