-----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, EuKQssBrOJQdXzxJic+oVlHEdfT5w2EaOzy8pKowjA0Yv8qz/NZck/bTaR/5sC+h 9MWJY5r2JhLcScPgzZO1pQ== 0000351817-05-000020.txt : 20050316 0000351817-05-000020.hdr.sgml : 20050316 20050315174101 ACCESSION NUMBER: 0000351817-05-000020 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050316 DATE AS OF CHANGE: 20050315 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SWIFT ENERGY CO CENTRAL INDEX KEY: 0000351817 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 742073055 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-08754 FILM NUMBER: 05682798 BUSINESS ADDRESS: STREET 1: 16825 NORTHCHASE DR STE 400 CITY: HOUSTON STATE: TX ZIP: 77060 BUSINESS PHONE: 2818742700 MAIL ADDRESS: STREET 1: 16825 NORTHCHASE DRIVE STREET 2: SUITE 400 CITY: HOUSTON STATE: TX ZIP: 77060 10-K 1 ee10k2004.txt 2004 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Year Ended December 31, 2004 Commission File Number 1-8754 SWIFT ENERGY COMPANY (Exact Name of Registrant as Specified in Its Charter) Texas 74-2073055 (State of Incorporation) (I.R.S. Employer Identification No.) 16825 Northchase Dr., Suite 400 Houston, Texas 77060 (281) 874-2700 (Address and telephone number of principal executive offices) Securities registered pursuant to Section 12(b) of the Act: Title of Class: Exchanges on Which Registered: Common Stock, par value $.01 per share New York Stock Exchange Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ ___ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No ___ ___ The aggregate market value of the voting stock held by non-affiliates at June 30, 2004 was approximately $599,027,785. The number of shares of common stock outstanding as of March 1, 2005 was 28,218,062 shares of common stock, $.01 par value. Documents Incorporated by Reference Document Incorporated as to Proxy Statement for the Annual Part II, Item 5 Meeting of Shareholders to be Part III, Items 10, 11, 12, 13 and 14 held May 10, 2005 1 Form 10-K Swift Energy Company and Subsidiaries 10-K Part and Item No. Page Part I Item 1. Business 3 Item 2. Properties 6 Item 3. Legal Proceedings 20 Item 4. Submission of Matters to a Vote of Security Holders 20 Part II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchasers of Equity Securities 20 Item 6. Selected Financial Data 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 23 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 42 Item 8. Financial Statements and Supple- mentary Data 44 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 80 Item 9A. Controls and Procedures 80 Item 9B. Other Information 80 Part III Item 10. Directors and Executive Officers of the Registrant (1) 81 Item 11. Executive Compensation (1) 81 Item 12. Security Ownership of Certain Bene- ficial Owners and Management and Related Stockholders Matters (1) 81 Item 13. Certain Relationships and Related Transactions (1) 81 Item 14 Principal Accountant Fees and Services (1) 81 Part IV Item 15 Exhibits and Financial Statement Schedules 82 (1) Incorporated by reference from Proxy Statement for the Annual Meeting of Shareholders to be held May 10, 2005. 2 PART I Items 1 and 2. Business and Properties See pages 18 and 19 for explanations of abbreviations and terms used herein. General Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas and onshore in New Zealand. We were founded in 1979 and are headquartered in Houston, Texas. At year-end 2004, we had estimated proved reserves of 799.8 Bcfe with a PV-10 Value of $2.0 billion. Our proved reserves at year-end 2004 were comprised of approximately 49% crude oil, 40% natural gas, and 11% NGLs, of which 56% were proved developed. Our proved reserves are concentrated 46% in Louisiana, 33% in Texas, and 18% in New Zealand. We currently focus primarily on development and exploration in four domestic core areas and two core areas in New Zealand: o AWP Olmos -- South Texas o Brookeland -- East Texas o Lake Washington -- South Louisiana o Masters Creek -- Central Louisiana o Rimu/Kauri -- New Zealand o TAWN -- New Zealand Competitive Strengths and Business Strategy Our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to achieve our goals. Our primary goals for the next five years are to increase proved oil and natural gas reserves at an average rate of 5% to 10% per year and to increase production at an average rate of 7% to 12% per year. Demonstrated Ability to Grow Reserves and Production We have grown our proved reserves from 454.8 Bcfe to 799.8 Bcfe over the five-year period ended December 31, 2004. Over the same period, our annual production has grown from 42.9 Bcfe to 58.3 Bcfe and our annual net cash provided by operations has increased from $73.6 million to $182.6 million. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities in our six core areas combined with producing property acquisitions. More recently, we increased our production by 10% during 2004 as compared to 2003 production. During 2004, our proved reserves decreased by 3%, which replaced 65% of our 2004 production, primarily due to a slowdown in drilling activity in Lake Washington in order to allow for the implementation of a three-dimensional seismic survey and facilities improvements in the area. Also, we focused our drilling efforts in 2004 mainly on development wells, which converted proved undeveloped reserves to proved developed, but did not increase our overall proved reserves. Based on our long-term historical performance and our business strategy going forward, we believe that we have the opportunities, experience, and knowledge to grow our reserves and production. Balanced Approach to Growth Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions. In general, we focus on drilling in our core 3 property and emerging growth areas when oil and natural gas prices are strong. When prices weaken and the per unit cost of acquisitions becomes more attractive, or a strategic opportunity exists, we shift our focus toward acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner. Over the five-year period ended December 31, 2004, we replaced 239% of our production at an average cost of $1.47 per Mcfe. For 2005, we are targeting total production and proved reserves to increase 7% to 12% over the 2004 levels. Our 2005 capital expenditures are currently budgeted at $200 million to $220 million, net of approximately $5 million to $15 million of non-core property dispositions. Approximately 80% of the budget is targeted for domestic activities, primarily in South Louisiana for Lake Washington and the surrounding area, with about 20% planned for activities in New Zealand. Approximately $15 million to $20 million will be focused on activities at our new properties in the Bay de Chene and Cote Blanche Island fields in South Louisiana that were acquired in December 2004. No acquisitions are currently included in our 2005 capital budget. We expect our 2005 capital expenditures will initially be at the low end of the range, and depending on commodity prices and operational performance, they may increase to the high end of the range during the course of the year. We anticipate 2005 capital expenditures to approximate our cash flow provided from operating activities during 2005. Reserve Replacement Ratio and Reserve Replacement Cost Historically we have added proved reserves due to both our drilling and acquisition activities. We believe that this strategy will continue to add reserves for us, however, external factors beyond our control, such as governmental regulations and commodity market factors, could limit our ability to drill wells and acquire proved properties in the future. We calculate and analyze reserve replacement ratios and costs to use as benchmarks against our competitors. These ratios and costs are limited in use by the inherent uncertainties in the reserve estimation process, and other factors discussed below. We have included a table listing the vintages of our proved undeveloped reserves in the table titled "Proved Undeveloped Reserves," and believe this table will provide an understanding of the time horizon required to convert proved undeveloped reserves to oil and gas production. Our reserve additions for each year are estimates. Reserve volumes can change over time and, therefore cannot be absolutely known or verified until all volumes have been produced and a cumulative production total for a well or field can be calculated. Many factors will impact our ability to access these reserves, such as availability of capital, new and existing government regulations, competition within our industry, the requirement of new or upgraded infrastructure at the production site, and technological advances. The reserve replacement ratio is calculated using reserve replacement volumes divided by production volumes during a specific period. The reserve replacement volumes used in this calculation are listed in the "Supplemental Information (Unaudited)" section of this report, specifically in a table titled "Supplemental Reserve Information." Within this table there are categories titled "Revisions of previous estimates," "Purchases of minerals in place" and "Extensions, discoveries, and other additions," which when added total the reserve replacement volumes. Production volumes are also listed in the same table, and these production volumes are also used in the reserve replacement ratio calculation. The reserve replacement cost is calculated using reserve replacement volumes divided by acquisition, exploration and development costs incurred during a specific period. Our acquisition, exploration, and development costs are listed in the "Supplemental Information (Unaudited)" section of this report, specifically in a table titled "Costs Incurred." Development costs as defined by Securities and Exchange Commission rules, include costs incurred to obtain access to proved reserves and provide facilities for extracting, treating, gathering and storing the oil and gas. Development costs thus include well costs for our development wells and facility costs, such as those facility and platform costs we have incurred in our Lake Washington area over the past several years. Costs incurred to explore and develop reserves may extend over several years. We believe a reserve replacement cost estimate is more meaningful when calculated over several periods. Future development costs from prior years are included in this calculation to the extent that they have been included, in our actual costs incurred. 4 Concentrated Focus on Core Areas with Operational Control The concentration of our operations in six core areas allows us to realize economies of scale in drilling and production by enabling us to manage larger producing fields with less personnel while minimizing incremental costs of increased drilling and completions. Our average lease operating costs, excluding taxes, were $0.71, $0.64, and $0.58 per Mcfe in 2004, 2003, and 2002, respectively. This concentration allows us to utilize the experience and knowledge we gain in these areas to continually improve our operations and guide us in developing our future activities and in operating similar type assets. For example, we will apply the experience we have gained in Lake Washington to our recently acquired Bay de Chene and Cote Blanche Island properties, which are also situated around South Louisiana salt domes. The value of this concentration is enhanced by our operating 97% of our proved oil and natural gas reserve base as of December 31, 2004. Retaining operational control allows us to more effectively manage production, control operating costs, allocate capital and time field development. Develop Under-Exploited Properties We are focused on applying modern technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties. For example, the Lake Washington field was discovered in the 1930s. We acquired our properties in this area for $30.5 million in 2001. Since that time, we have increased our average daily net production from less than 700 BOE to 12,900 BOE for the quarter ended December 31, 2004. We have also increased our proved reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 45.4 million BOE or 272.5 Bcfe, as of December 31, 2004. Additionally, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest. We have drilled 32 wells in New Zealand since 1999. When we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas also had significant additional development potential. Our properties in the Bay de Chene and Cote Blanche Island fields hold mainly proved undeveloped reserves and we intend to begin our initial development activities of these properties in the second half of 2005. We intend to continue acquiring large acreage positions in under-explored and under-exploited areas, where we can apply modern technologies and our experience and knowledge in the areas to grow production from developed fields. Capitalize on the Near Term Depletion of New Zealand's Largest Gas Field The Maui field in New Zealand currently supplies over 70% of the natural gas produced in New Zealand. The Maui field is expected to be depleted by 2007, which has caused significant upward pressure on prices for natural gas in the country. Due to currency exchange increases between the New Zealand Dollar and the U.S. Dollar, along with increases in our natural gas contract prices, our average natural gas price in New Zealand has increased 77% from the first quarter of 2003 to the fourth quarter of 2004. We expect the prices we receive for our natural gas in New Zealand to continue to remain strong in the foreseeable future. During 2005, we anticipate drilling seven to ten development wells and expect to drill three to five exploration tests, which includes our Tarata Thrust exploration activity. These New Zealand activities provide us with long-term growth opportunities and significant potential reserves in a country with stable political and economic conditions, existing oil and gas infrastructure, and favorable tax and royalty regimes. Maintain Financial Flexibility and Disciplined Capital Structure We practice a disciplined approach to financial management and have historically maintained a disciplined capital structure to provide us with the ability to execute our business plan. As of December 31, 2004, our debt to capitalization was approximately 43%, debt per proved reserves was $0.45 per Mcfe, and our debt to PV-10 ratio was 18%. We plan to maintain a capital structure that provides financial flexibility through the prudent use of capital, aligning our capital expenditures to our cash flows, and an active hedging program. The combination of hedging with collars, floors, forward sales, and the sale of our New Zealand natural gas production under long-term, fixed-price contracts will provide for a more stable cash flow for the limited periods covered as described in the "Commodity Risk" section of this report. Experienced Technical Team We employ 42 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 25 years of experience in their technical fields and have been employed by us for an average of over eight years. In addition, we engage 5 experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other services. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations. We have increasingly used seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, post-stack image enhancement reprocessing, amplitude versus offset datasets, correlation cubes, and detailed formation depletion studies. In 2004, we completed our three dimensional seismic survey covering our Lake Washington area and at least four of our 2005 wells in this area will be exploration wells with targets derived from this 3-D seismic data. We use various recovery techniques, including gas lift, water flooding, and acid treatments to enhance crude oil and natural gas production. We also fracture reservoir rock through the injection of high-pressure fluid, install gravel packs, and insert coiled-tubing velocity strings to enhance and maintain production. We believe that the application of fracturing and coiled-tubing technology has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area. When appropriate, we develop new applications for existing technology. For example, in New Zealand we acquired seismic data by effectively combining marine seismic data with land seismic data, an application we have not seen any other company use in New Zealand. We have developed an expertise in drilling horizontal wells at vertical depths below 10,000 feet, often in a high-pressure environment, involving single or dual lateral legs of several thousand feet. This results in an integrated approach to exploration using multidisciplinary data analysis and interpretation that has helped us identify a number of exploration prospects. We also employ measurement-while-drilling techniques extensively in our Lake Washington area, which allows us to guide the drill bit during the drilling process. This technology allows Swift Energy to steer the well bore path parallel to the salt face and to intersect multiple targeted sands in a single well bore. Operating Areas The following table sets forth information regarding our proved reserves and production in our six core areas: % of Year-End 2004 Proved % of 2004 Area Location Reserves Production ---- ------------------- -------------- ---------- AWP Olmos..............South.Texas...................24% 15% Brookeland.............East.Texas.....................5% 6% Lake Washington........South.Louisiana...............34% 40% Masters Creek..........Central.Louisiana..............7% 6% Rimu/Kauri.............New.Zealand...................14% 9% TAWN...................New.Zealand....................5% 19% --- --- % of Total........................................89% 95% --- --- Domestic Core Operating Areas AWP Olmos Area. As of December 31, 2004, we owned 27,534 net acres in the AWP Olmos Area in South Texas. We have extensive experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 69% natural gas. At year-end 2004, we owned interests in and operated 512 wells in this area producing natural gas from the Olmos sand formation at depths of approximately 9,000 to 11,500 feet. We own nearly 100% of the working interests in all our operated wells. In 2004, we completed 13 development wells in this area, and performed four fracture enhancements. At year-end 2004, we had 112 proved undeveloped locations. Our planned 2005 capital expenditures in this area will focus on drilling 12 to 15 wells in this area. Brookeland Area. As of December 31, 2004, we owned drilling and production rights in 79,040 net acres and 3,500 fee mineral acres in the Brookeland area, which contains substantial proved undeveloped reserves. This area is 6 located in East Texas near the border of Louisiana in Jasper and Newton counties. We primarily drill horizontal wells and produce from the Austin Chalk formation. The reserves are approximately 56% oil and natural gas liquids. At year-end 2004, we had 11 proved undeveloped locations. Our planned 2005 capital expenditures in this area include drilling one to two development wells. Lake Washington Area. As of December 31, 2004, we owned drilling and production rights in 15,199 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana, along with lease and seismic options covering another 6,645 acres. Approximately 92% of our proved reserves of 45.4 million BOE in this area at December 31, 2004 were oil and NGLs. To date, we have primarily produced from multiple Miocene sands ranging in depth from greater than 1,700 feet to less than 9,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its inception in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 109 producing wells is gathered from three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with rigs on barges. In 2004, we drilled 23 development wells and seven exploratory wells, of which 19 development and two exploratory wells were completed. At year-end 2004, we had 85 proved undeveloped locations in this field. Our planned 2005 capital expenditures in this area will focus on drilling at least 30 wells, of these at least four will be exploratory wells with targets derived from recently acquired three-dimensional data. Additional facility work is planned to further improve the deliverability and efficiency in this area. Masters Creek Area. As of December 31, 2004, we owned drilling and production rights in 48,810 net acres and 91,994 fee mineral acres in the Masters Creek area, which contains substantial proved undeveloped reserves. This area is located in Central Louisiana near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 68% oil and NGLs. In 2004, we drilled and successfully completed one development well in this area. At year-end 2004, we had nine proved undeveloped locations. Our planned 2005 capital expenditures include drilling one to two development wells. Domestic Emerging Growth Areas Garcia Ranch Area. We have been focusing on the deep sands of the Frio formation (10,000 to 16,000 feet) in an area known as Garcia Ranch, which straddles the border of Kenedy County and Willacy County in the southern tip of Texas. Three exploratory wells and one development well were drilled in this area in 2004, of which two exploratory wells were completed. Bay de Chene and Cote Blanche Island. In December 2004, we acquired approximately 14,200 gross acres in the Bay de Chene field and approximately 6,200 gross acres in the Cote Blanche Island field, both of which are in South Louisiana in close proximity to Lake Washington. Bay de Chene is located in Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in St. Mary Parish. These fields hold predominantly undeveloped reserves. We plan to spend $15 million to $20 million to begin developing these fields in the later part of 2005. These fields were shut-in following the acquisition for facility enhancements and to repair a gas supply line. New Zealand Core Operating Areas Our activity in New Zealand began in 1995. As of December 31, 2004, our exploration permit 38719, which we operate, included approximately 72,769 acres in the Taranaki Basin of New Zealand's north island. In April 2004, two other permits (38756 and 38759) within the Taranaki Basin were consolidated with our permit 38719 to form one permit area. This acreage includes our Rimu/Kauri area, our Rimu mining permit area, and our Tawa prospect. Rimu/Kauri Area. Since 2002, we have held a 100% working interest in petroleum mining permit 38151 covering approximately 5,500 acres in the Rimu area for a primary term of 30 years. We began commercial production from the Rimu area in May 2002. During 2004, we completed ten of 11 wells in the Kauri area. Five of these wells successfully targeted the Kauri sands, and five were completed in the Manutahi sand. We have applied for a 30-year primary term mining permit covering approximately 8,714 acres in the Kauri area. Our natural gas production from this area is sold to Genesis Power Ltd. under a long-term contract for use at its Huntly Power Station, New Zealand's largest thermal power station. 7 TAWN Area. Our interest in TAWN consists of a 100% working interest in four petroleum mining permits, 38138 through 38141, covering producing oil and gas fields and extensive associated hydrocarbon-processing facilities and pipelines. The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names -- the Tariki field, the Ahuroa field, the Waihapa field, and the Ngaere field. The four fields include 18 wells where the purchaser of gas, Contact Energy, has contracted to take minimum quantities and can call for higher production levels to meet electrical demand in New Zealand. In 2004, we completed the Tariki-D1 well in this area. The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area. Our infrastructure at TAWN includes two hydrocarbon-processing plants with significant excess capacity. We also own the pipelines connecting the fields and facilities to export terminals and interior markets. New Zealand Emerging Growth Areas The Tawa prospect, which is scheduled for drilling in 2005, is located in permit 38719 northwest of the Rimu area. Its main targets are the Kauri, Tariki, and Kapuni sands. Consisting of a combination of structural and stratigraphic traps, this prospect was developed based upon our analysis of existing two and three-dimensional seismic data. The Tawa prospect may also include a shallower prospect located on the southeast flank of the prospect. Two prospects, also scheduled for drilling in 2005, are located in our TAWN area and are identified as the Goss prospect (Goss A1 well), and the Trapper prospect (Trapper A1 well). Both prospects will have the Kapuni group sands (the major reservoir in the basin) as their main target, but as these wells are drilled they will also pass through the Tariki sandstone and other major producing sands in the basin .We have entered into a series of farm-out agreements with Mighty River Power ("MRP"), a state owned New Zealand utility, that provide for a 50% working interest in relation to the Goss A1 well, the Trapper A1 well, and a well on our Tawa prospect. Under the farm-out agreement, MRP will provide the funding for the drilling of the three exploration wells to earn a 50% working interest in any commercial discoveries resulting from these prospects. Once MRP has earned its 50%, we will equally share any future development costs subject to the terms of the agreements. Swift will continue to maintain its 100% working interest in the existing producing horizons and facilities in both the TAWN and Rimu/Kauri areas. Swift also holds a 71% interest in exploration permit 38718, covering approximately 28,600 gross acres northeast of our TAWN area, and a 21% interest in exploration permit 38716, covering approximately 33,000 gross acres southeast of our TAWN area. In December 2004, we entered into a farm-in agreement with Ballance Agri-Nutrients Limited of New Zealand for 60% of their exploration permit 38742. The approximately 16,800 gross acre permit is located onshore in the north-central Taranaki Basin. Under the terms of the contract we became the operator of the permit and anticipate drilling an exploratory well in this area in the second half of 2005. 8 Summary of New Zealand Government Licenses and Permits Our acreage in New Zealand is licensed from the New Zealand government under both production exploration permits (PEP), production mining licenses (PML), and production mining permits (PMP). These licenses and permits are summarized in the following table: Date Swift Acquired / Granted Swift's Permit Initial Interest Interest PEP 38716 1999 21% PEP 38718 2000 71% PEP 38719 1996 100% PEP 38742 2004 60% PML 38138 2002 100% PML 38139 2002 100% PML 38140 2002 100% PML 38141 2002 100% PMP 38151 2002 100% The New Zealand government's Crown Minerals website has details of these licenses at http://crownminerals.med.govt.nz/index.asp. Oil and Natural Gas Reserves The following tables present information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2004, 2003, and 2002. The information set forth in the tables regarding reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy has audited 100% of our proved reserves. Gruy's audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy's audit was based upon review of all available production histories and other geological, economic, and engineering data, all of which was provided by us. Estimates of future net revenues from our proved reserves and the PV-10 Value are made using oil and gas sales prices in effect as of the dates of such estimates adjusted for the effects of hedging and are held constant, for that year's reserve calculation, throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. Our hedges at year-end 2004 consisted mainly of crude oil and natural gas price floors with strike prices lower than the period-end price and thus did not materially affect prices used in these calculations. The weighted averages of such year-end 2004 prices domestically were $5.87 per Mcf of natural gas, $42.21 per barrel of oil, and $26.49 per barrel of NGL, compared to $5.53, $30.88, and $21.81 at year-end 2003 and $4.23, $29.36, and $17.30 at year-end 2002, respectively. The weighted averages of such year-end 2004 prices for New Zealand were $3.07 per Mcf of natural gas, $33.60 per barrel of oil, and $20.48 per barrel of NGL, compared to $2.04, $26.78, and $14.10 in 2003 and $1.48, $28.80, and $12.24 in 2002, respectively. The weighted averages of such year-end 2004 prices for all our reserves, both domestically and in New Zealand, were $5.16 per Mcf of natural gas, $41.07 per barrel of oil, and $25.48 per barrel of NGL, compared to $4.56, $30.16, and $20.61 in 2003 and $3.49, $29.27, and $16.54 in 2002, respectively. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as proved and are not reflected in the following tables. The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the SEC and its PV-10 Value as of December 31, 2004, 2003, and 2002. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in supplemental information to our consolidated financial statements, 9 which is calculated after provision for future income taxes. We combine NGLs with oil for reserve reporting purposes. As of December 31, 2004 Total Domestic New Zealand Estimated Proved Oil and Natural Gas Reserves Natural gas reserves (MMcf): Proved developed......................................................... 193,311 140,549 52,762 Proved undeveloped....................................................... 124,935 97,343 27,593 ------------- ------------- ----------- Total................................................................... 318,246 237,892 80,355 ============= ============= =========== Oil reserves (MBbl): Proved developed......................................................... 42,038 36,629 5,409 Proved undeveloped....................................................... 38,229 32,510 5,719 ------------- ------------- ----------- Total................................................................... 80,267 69,139 11,128 ============= ============= =========== Estimated Present Value of Proved Reserves (In thousands) Proved developed.........................................................$ 1,181,748 $ 1,037,617 $ 144,130 Proved undeveloped....................................................... 839,127 759,724 79,403 ------------- ------------- ----------- PV-10 Value.............................................................$ 2,020,875 $ 1,797,341 $ 223,533 ============= ============= =========== As of December 31, 2003 Total Domestic New Zealand Estimated Proved Oil and Natural Gas Reserves Natural gas reserves (MMcf): Proved developed......................................................... 210,120 138,173 71,947 Proved undeveloped....................................................... 125,685 104,148 21,537 ------------- ------------- ----------- Total................................................................... 335,805 242,321 93,484 ============= ============= =========== Oil reserves (MBbl): Proved developed......................................................... 45,525 38,768 6,757 Proved undeveloped....................................................... 35,235 28,248 6,987 ------------- ------------- ----------- Total................................................................... 80,760 67,016 13,744 ============= ============= =========== Estimated Present Value of Proved Reserves (In thousands) Proved developed.........................................................$ 940,883 $ 805,834 $ 135,049 Proved undeveloped....................................................... 597,912 517,485 80,427 ------------- ------------- ----------- PV-10 Value.............................................................$ 1,538,795 $ 1,323,319 $ 215,476 ============= ============= =========== As of December 31, 2002 Total Domestic New Zealand Estimated Proved Oil and Natural Gas Reserves Natural gas reserves (MMcf): Proved developed......................................................... 233,515 149,732 83,783 Proved undeveloped....................................................... 93,217 90,092 3,125 ------------- ------------- ----------- Total................................................................... 326,732 239,824 86,908 ============= ============= =========== Oil reserves (MBbl): Proved developed......................................................... 35,928 26,530 9,398 Proved undeveloped....................................................... 34,511 32,500 2,011 ------------- ------------- ----------- Total................................................................... 70,439 59,030 11,409 ============= ============= =========== Estimated Present Value of Proved Reserves (In thousands) Proved developed.........................................................$ 679,356 $ 516,833 $ 162,523 Proved undeveloped....................................................... 481,833 456,632 25,201 ------------- ------------- ----------- PV-10 Value.............................................................$ 1,161,189 $ 973,465 $ 187,724 ============= ============= ===========
Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves. 10 No other reports on our reserves have been required to be filed, nor have any been filed with any federal agency. Proved Undeveloped Reserves The following table sets forth the aging and PV-10 value of our proved undeveloped reserves as of December 31, 2004:
PV-10 Volume % of PUD Value % of PUD Year Added (Bcfe) Volumes (in millions) PV-10 Value 2004 111.5 31% $ 367.5 44% 2003 80.0 23% 205.2 24% 2002 30.6 9% 61.7 7% 2001 17.7 5% 40.1 5% 2000 43.4 12% 54.8 7% Prior to 2000 71.0 20% 109.1 13% ----------- ------------- ----------------- ---------------- Total 354.2 100% $ 838.4 100% =========== ============= ================= ================
Sensitivity of Reserves to Pricing As of December 31, 2004, a 5% increase in crude oil an NGL pricing would increase our total estimated proved reserves of 799.8 Bcfe by approximately 0.6 Bcfe, and increase the total PV-10 value of $2.0 billion by approximately $89 million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.7 Bcfe and decrease the total PV-10 value by approximately $89 million. As of December 31, 2004 a 5% increase in natural gas pricing (exclusive of fixed contract volumes) would increase our total estimated proved reserves by approximately 0.6 Bcfe and increase the total PV-10 value by approximately $33 million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed contract volumes) would decrease our total estimated proved reserves ay approximately 0.6 Bcfe and decrease the total PV-10 value by approximately $34 million. Oil and Gas Wells The following table sets forth the gross and net wells in which we owned an interest at the following dates: Oil Wells Gas Wells Total Wells(1) December 31, 2004: Gross................................358.......574...........932 Net................................308.8.....525.9.........834.7 December 31, 2003: Gross................................397.......560...........957 Net................................340.6.....504.0.........844.6 December 31, 2002: Gross................................342.......555...........897 Net................................278.9.....479.8.........758.7 - ------------ (1) Excludes 40 service wells in 2004, 41 service wells in 2003, and 35 service wells in 2002. 11 Oil and Gas Acreage As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so. The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2004: Developed(1) Undeveloped(1) ------------------------- -------------------------- Gross Net Gross Net ---------- ---------- ----------- ----------- Alabama................ 9,046.11 2,588.73 124.22 79.82 Louisiana..............100,464.00 82,814.43 16,342.11 11,481.30 Texas..................151,824.86 103,029.72 17,765.95 9,396.36 Wyoming................ 681.07 151.06 66,015.91 64,252.13 All other states....... 320.00 266.66 400.00 257.32 Offshore Louisiana..... 4,609.37 276.56 5,000.00 258.34 Offshore Texas......... 2,880.00 74.39 -- -- ---------- ---------- ----------- ------------ Total Domestic.......269,825.41 189,201.55 105,648.19 85,725.27 New Zealand............ 8,240.00 7,865.60 173,043.90 132,578.17 ---------- ---------- ----------- ------------ Total...............278,065.41 197,067.15 278,692.09 218,303.44 ========== ========== =========== ============ (1) Fee mineral acres acquired in the Brookeland and Masters Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 69,149 undeveloped fee mineral acres for a total of 95,494 fee mineral acres. Drilling Activities The following table sets forth the results of our drilling activities during the three years ended December 31, 2004:
Gross Wells Net Wells ------------------------- ------------------------- Year Type of Well Total Producing Dry Total Producing Dry ---- ----------------------- ------ --------- ------- ------- --------- ------ 2004 Exploratory -- Domestic 10 4 6 7.5 2.3 5.2 Development -- Domestic 44 37 7 41.7 35.0 6.7 Exploratory -- New 1 -- 1 1.0 -- 1.0 Zealand Development -- New 11 10 1 11.0 10.0 1.0 Zealand 2003 Exploratory -- Domestic 8 5 3 7.3 5.0 2.3 Development -- Domestic 63 53 10 61.9 51.9 10.0 Exploratory -- New 1 -- 1 0.5 -- 0.5 Zealand Development -- New 3 3 -- 3.0 3.0 -- Zealand 2002 Exploratory -- Domestic 7 3 4 5.0 2.3 2.7 Development -- Domestic 23 17 6 23.0 17.0 6.0 Exploratory -- New 3 2 1 2.2 2.0 0.2 Zealand Development -- New 3 2 1 3.0 2.0 1.0 Zealand
12 Operations We generally seek to be operator in the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide all the equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties. Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator's direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities in 2004 totaled $5.8 million and ranged from $600 to $2,155 per well per month. Marketing of Production Domestically, we typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We typically sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. Shell, both domestically and in New Zealand accounted for 10% or more of our total revenues during the year ended December 31, 2004, with purchases accounting for approximately 48% of total oil and gas sales. For the year-ended December 31, 2003, Shell, both domestically and in New Zealand, and Contact Energy in New Zealand together accounted for approximately 26% of our total oil and gas sales. However, due to the availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues. In 1998, we entered into gas processing and gas transportation agreements for our natural gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, and then assumed by Enterprise Hydrocarbons L.P. in September 2004, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one- year extensions unless earlier terminated. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future. Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our natural gas production from these areas is processed under long term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market at prevailing prices. Our oil production from the Lake Washington area is delivered into ExxonMobil's crude oil pipeline system or transported on barges for sales to various purchasers at prevailing market prices or at fixed prices tied to the then current Nymex crude oil contract for the applicable month(s) Our natural gas production from this area is either consumed on the lease or is delivered into El Paso's Tennessee Gas Pipeline system and then sold in the spot market at prevailing prices. Our oil production in New Zealand is sold to Shell Petroleum Mining at international prices tied to the Asia Petroleum Price Index (APPI) Tapis posting, less the cost of storage, trucking, and transportation. Our natural gas production from our TAWN fields is sold under a long-term fixed price contract with Contact Energy. Our natural gas production from the Rimu field is sold to Genesis Power Ltd. under a long-term fixed price contract that was modified in 2003 and covers approximately 7.2 Bcfe per year for a three-year period. During 2004, additional production volumes from our fields, over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at prevailing market rates. Production of NGLs in New Zealand is sold to Rockgas Ltd. under long-term contracts tied to New Zealand's domestic natural gas liquids market. 13 The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production for the three-year period ended December 31, 2004. Year Ended December 31, 2004 2003 2002 ---- ---- ---- Net Sales Volume: Oil (MBbls)(1)........................... 4,722 3,369 2,597 Natural Gas Liquids (MBbls)(2)........... 1,040 823 1,174 Natural gas (MMcf)(3).................... 23,742 28,003 27,132 Total (MMcfe)........................... 58,319 53,158 49,752 Average Sales Price: Oil (Per Bbl)(1).........................$ 40.24 $ 29.89 $ 24.52 Natural Gas Liquids (Per Bbl)(2).........$ 22.52 $ 17.60 $ 12.82 Natural gas (Per Mcf)(3).................$ 4.12 $ 3.42 $ 2.30 Average Production Cost (Per Mcfe).........$ 1.23 $ 0.99 $ 0.83 - ------------ (1) Oil production for 2004, 2003, and 2002 includes New Zealand production of 452,753 barrels at an average price per barrel of $42.15, 572,683 barrels at an average price per barrel of $29.58, and 483,591 barrels at an average price per barrel of $24.31, respectively. (2) Natural gas liquids production for 2004, 2003 and 2002 includes New Zealand production of 350,303 barrels at an average price of $17.96 per barrel, 283,227 barrels with an average price of $13.50 per barrel, and 211,864 barrels with an average price of $11.06 per barrel. (3) Natural gas production for 2004, 2003 and 2002 includes New Zealand production of 11,441,954 Mcf with an average price of $2.38 per Mcf, 14,258,679 Mcf with an average price of $1.83 per Mcf, and 11,351,518 Mcf with an average price of $1.32 per Mcf. Risk Management Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, and fires, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. We maintain comprehensive insurance coverage, including general liability insurance in an amount not less than $50 million. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident, or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us. Commodity Risk The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. At December 31, 2004, we had in place price floors in effect through the December 2005 contract month for natural gas; these cover a portion of our domestic natural gas production for January 2005 to December 2005. The natural gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted average floor price of $5.83 per MMBtu. Our natural gas price floors in place at December 31, 2004 are expected to cover approximately 30% to 35% of our domestic natural gas production from January 2005 to December 2005. At December 31, 2004, we also had in place price crude oil price floors in effect through the March 2005 contract month, which cover a portion of our domestic crude oil production for January 2005 to March 2005. The crude oil price floors cover notional volumes of 216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil price floors in place at December 31, 2004 are expected to cover approximately 15% to 20% of our domestic crude oil production from January 2005 to March 2005. 14 Competition We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Regulations Environmental Regulations Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future. We currently own or lease, and have in the past owned or leased, numerous properties in connection with our domestic operations that have been used for the exploration and production of oil and gas for many years. Although we have used operation and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as "CERCLA" or the "Superfund" law, the federal Resource Conservation and Recovery Act or "RCRA," the federal Clean Water Act, the federal Clean Air Act, the federal Oil Pollution Act or "OPA," and analogous state laws. Under such laws and any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment. Our domestic operations offshore in the Gulf of Mexico are subject to OPA, which imposes a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party fails to report the spill or cooperate fully in any resulting cleanup. The OPA also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with OPA requirements. 15 Our operations in New Zealand could also potentially be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior operators, closure and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations. While we believe that we are in substantial compliance with current environmental laws and regulations in New Zealand, and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future. United States Federal, State and New Zealand Regulation of Oil and Natural Gas The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission ("FERC") is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC's jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. Our sales of crude oil, condensate and NGLs are not currently subject to FERC regulation. However, the ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation. Production of any oil and gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the rate that a well would otherwise produce in the absence of such regulation. In addition, certain state regulatory authorities can limit the number of wells or the locations where wells may be drilled. Any of these actions could negatively affect the amount or timing of revenues. Likewise, the government of New Zealand regulates the exploration, production, sales, and transportation of oil and natural gas. Federal Leases Some of our domestic properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and administrative orders affect the terms of leases, and in turn may affect our exploration and development plans, methods of operation, and related matters. Litigation In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. Employees At December 31, 2004, we employed 272 persons. Of these employees, 69 were in New Zealand, including four expatriate employees. Eight of our New Zealand employees are members of a union. None of our other employees are represented by a union. Relations with employees are considered to be good. 16 Facilities At December 31, 2004, we occupied approximately 102,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2015. The lease requires payments of approximately $194,000 per month. In New Zealand we leased approximately 16,000 square feet of office space, under leases expiring in 2008 and 2009. These New Zealand leases require payments of approximately $15,000 per month. We also have field offices in various locations from which our employees supervise local oil and gas operations. Available Information Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, changes in and stock ownership of our directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act can be accessed free of charge on our web site at www.swiftenergy.com as soon as reasonably practicable after we electronically file these reports with the SEC. All exhibits and supplemental schedules to these reports are available free of charge through the SEC web site at www.sec.gov. In addition, we have adopted a Code of Ethics for Senior Financial Officers and Principal Executive Officer. We have posted this Code of Ethics on our website, where we also intend to post any waivers from or amendments to this Code of Ethics. 17 Glossary of Abbreviations and Terms The following abbreviations and terms have the indicated meanings when used in this report: Bbl -- Barrel or barrels of oil. Bcf -- Billion cubic feet of natural gas. Bcfe -- Billion cubic feet of natural gas equivalent (see Mcfe). BOE -- Barrels of oil equivalent. Development Well -- A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. Discovery Cost -- With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions. Dry Well -- An exploratory or development well that is not a producing well. EBITDA -- Earnings before interest, taxes, depreciation, depletion and amortization. EBITDAX -- Earnings before interest, taxes, depreciation, depletion and amortization, and exploration expenses. Since Swift uses full-cost accounting for oil and property expenditures, as noted in footnote one of the accompanying consolidated financial statements, exploration expenses are not applicable to Swift. Exploratory Well -- A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir. FASB -- The Financial Accounting Standards Board. Gigajoules -- A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural gas. Gross Acre -- An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. Gross Well -- A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. MBbl -- Thousand barrels of oil. Mcf -- Thousand cubic feet of natural gas. Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas. MMBbl -- Million barrels of oil. MMBtu -- Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale. MMcf -- Million cubic feet of natural gas. 18 MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe). Net Acre -- A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Net Well -- A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. NGL-- Natural gas liquid. Producing Well -- An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. * Proved Developed Oil and Gas Reserves -- Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. * Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made. * Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved Undeveloped (PUD) Locations -- A location containing proved undeveloped reserves. PV-10 Value -- The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. Reserves Replacement Cost -- With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period. SFAS -- Statement of Financial Accounting Standards. TAWN -- New Zealand producing properties acquired by Swift in January 2002. TAWN is comprised of the Tariki, Ahuroa, Waihapa, and Ngaere fields. * These definitions regarding various types of proved reserves are only abbreviated versions of the Securities and Exchange Commission's definitions of these terms contained in Rule 4-10(a) of Regulation S-X. See www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the full text of the SEC's definitions of these terms. 19 Item 3. Legal Proceedings No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business. Item 4. Submission of Matters to a Vote of Security Holders No matters were submitted during the fourth quarter of 2004 to a vote of security holders. PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Common Stock, 2003 and 2004 Our common stock is traded on the New York Stock Exchange and the Pacific Exchange, Inc., under the symbol "SFY." The high and low quarterly sales prices for the common stock for 2003 and 2004 were as follows: 2003 2004 ----------------------------------- ------------------------------------ First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter ----------------------------------- ------------------------------------ Low $8.51 $7.60 $10.64 $13.57 $15.90 $18.72 $18.16 $23.50 High $9.76 $12.14 $14.57 $18.00 $20.02 $22.75 $25.16 $30.34 Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, as discussed in Note 4 to the consolidated financial statements, and we presently intend to continue a policy of using retained earnings for expansion of our business. We had approximately 298 stockholders of record as of December 31, 2004. Equity Compensation Plan Information Information regarding our equity compensation plans, including both shareholder approved plans and plans not approved by shareholders, is set forth in Proxy Statement for our annual meeting to be held May 10, 2005 ("Proxy Statement"), which Proxy Statement is to be filed within 120 days after Registrant's fiscal year end of December 31,2004, and which information is incorporated by reference. 20 Item 6. Selected Financial Data
2004 2003 2002 2001 2000 Total Revenues $310,276,774 $208,900,983 $149,969,811 $183,807,490 $191,624,946 Income (Loss) Before Income Taxes and Change in Accounting Principle (1) $101,440,242 $50,739,178 $18,408,289 ($34,192,333) 92,449,488 Net Income (Loss) $68,450,917 $29,893,812 $11,923,227 ($22,347,765) $59,184,008 Net Cash Provided by Operating Activities $182,582,887 $110,827,279 $71,626,314 $139,884,255 $128,197,227 Per Share Data Weighted Average Shares Outstanding(1) 27,822,413 27,357,579 26,382,906 24,732,099 21,244,684 Earnings (Loss) per Share--Basic(1) $2.46 $1.09 $0.45 ($0.90) $2.79 Earnings (Loss) per Share--Diluted(1) $2.41 $1.08 $0.45 ($0.90) $2.51 Shares Outstanding at Year-End 28,089,764 27,484,091 27,201,509 24,795,564 24,608,344 Book Value per Share at Year-End $16.88 $14.46 $13.42 $12.61 $13.50 Market Price(1) High $30.34 $18.00 $20.58 $37.70 $43.50 Low $15.90 $7.60 $6.80 $16.66 $9.75 Year-End Close $28.94 $16.85 $9.67 $20.20 $37.63 Effect on Net Income and Earnings Per Share From Changes in Accounting Principles (2) Cumulative Effect of Change in Accounting Principle (Net of Taxes) --- ($4,376,852) --- ($392,868) --- Effect per Share--Basic --- ($0.16) --- ($0.01) --- Effect per Share--Diluted --- ($0.16) --- ($0.01) --- Assets Current Assets $54,385,996 $33,460,957 $29,768,199 $36,752,980 $41,872,879 Oil and Gas Properties, Net of Accumulated Depreciation, Depletion, and Amortization $923,438,160 $815,807,003 $721,617,941 $628,304,060 $524,052,828 Total Assets $990,573,147 $859,838,544 $767,005,859 $671,684,833 $572,387,001 Liabilities Current Liabilities $68,618,291 $69,353,342 $46,884,184 $73,245,335 $64,324,771 Long-Term Debt $357,500,000 $340,254,783 $324,271,973 $258,197,128 $134,729,485 Total Liabilities $516,401,007 $462,447,280 $401,932,675 $359,032,113 $240,232,846 Stockholders' Equity $474,172,140 $397,391,264 $365,073,184 $312,652,720 $332,154,155 Number of Employees 272 241 234 209 181 Producing Wells Swift Operated 835 870 820 854 817 Outside Operated 97 128 112 381 711 Total Producing Wells 932 998 932 1,235 1,528 Wells Drilled (Gross) 66 75 36 53 70 Proved Reserves Natural Gas (Mcf) 318,246,294 335,804,862 326,731,672 324,912,125 418,613,976 Oil, NGL, & Condensate (barrels) 80,267,208 80,759,903 70,438,963 53,482,636 35,133,596 Total Proved Reserves (Mcf equivalent) 799,849,539 820,364,284 749,365,449 645,807,939 629,415,552 Production (Mcf equivalent)(3) 58,318,502 53,158,384 49,752,346 44,791,202 42,356,705 Average Sales Price Natural Gas (per Mcf) $4.12 $3.42 $2.30 $4.23 $4.24 Natural Gas Liquids (per barrel)(4) $22.52 $17.60 $12.82 --- --- Oil (per barrel)(4) $40.24 $29.89 $24.52 $22.64 $29.35 Mcf Equivalent $5.34 $3.97 $2.84 $4.05 $4.47
1)Amounts have been retroactively restated in all periods presented to give recognition to: (a) an equivalent change in capital structure as a result of two 10% stock dividends, one in September 1994, the other in October 1997; (b) the adoption in 1998 of Statement of Financial Accounting Standards No. 128, "Earnings per Share," and (c) the adoption in 2003 of Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which affected our presentation of 1999 results by reclassifying the loss on early extinguishment of debt from an extraordinary item to an operating item. 2)We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. We adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Transactions" on January 1, 2001. As of January 1, 1994, we changed our revenue recognition policy for earned interests. 3)Natural gas production from 1994 to 2000 includes volumes under a production payment agreement ranging from 1.4 Bcfe in 1994 to 0.4 Bcfe in 2000. 4)Prior to 2002, we combined NGLs with natural gas for reporting purposes. 21
1999 1998 1997 1996 1995 1994 $110,671,007 $82,469,221 $74,712,180 $56,298,026 $25,092,230 $21,624,231 $29,736,151 ($73,391,581) $33,129,606 $28,785,783 $6,894,537 $4,837,829 $19,286,574 ($48,225,204) $22,310,189 $19,025,450 $4,912,512 ($13,047,027) $73,603,426 $54,249,017 $55,255,965 $37,102,578 $14,376,463 $10,394,514 18,050,106 16,436,972 16,492,856 15,000,901 10,035,143 7,308,673 $1.07 ($2.93) $1.35 $1.27 $0.49 ($1.79) $1.07 ($2.93) $1.26 $1.25 $0.49 ($1.79) 20,823,729 16,291,242 16,459,156 15,176,417 12,509,700 6,685,137 $8.18 $6.71 $9.69 $9.41 $7.46 $6.30 $13.31 $21.00 $34.20 $28.86 $11.48 $10.35 $5.69 $6.94 $16.93 $9.89 $7.05 $7.75 $11.50 $7.38 $21.06 $27.16 $10.91 $8.86 --- --- --- --- --- ($16,772,698) --- --- --- --- --- ($2.52) --- --- --- --- --- ($2.52) $50,605,488 $35,246,431 $29,981,786 $101,619,478 $43,380,454 $39,208,418 $392,986,589 $356,711,711 $301,312,847 $200,010,375 $125,217,872 $88,415,612 $454,299,414 $403,645,267 $339,115,390 $310,375,264 $175,252,707 $135,672,743 $34,070,085 $31,415,054 $28,517,664 $32,915,616 $40,133,269 $52,345,859 $239,068,423 $261,200,000 $122,915,000 $115,000,000 $28,750,000 $28,750,000 $283,895,297 $294,282,628 $179,714,470 $167,613,654 $81,906,742 $93,545,612 $170,404,117 $109,362,639 $159,400,920 $142,761,610 $93,345,965 $42,127,131 173 203 194 191 176 209 769 836 650 842 767 750 788 917 917 986 3,316 3,422 1,557 1,753 1,567 1,828 4,083 4,172 27 75 182 153 76 44 329,959,750 352,400,835 314,305,669 225,758,201 143,567,520 76,263,964 20,806,263 13,957,925 7,858,918 5,484,309 5,421,981 4,553,237 454,797,327 436,148,385 361,459,177 258,664,055 176,099,406 103,583,566 42,874,303 39,030,030 25,393,744 19,437,114 11,186,573 9,600,867 $2.40 $2.08 $2.68 $2.57 $1.77 $1.93 --- --- --- --- --- --- $16.75 $11.86 $17.59 $19.82 $15.66 $14.35 $2.54 $2.05 $2.72 $2.71 $2.01 $2.06
22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis supplements and is provided to facilitate increased understanding of our 2004, 2003 and 2002 consolidated financial statements and our accompanying notes included with this report. Overview For 2004, we had revenues of $310.3 million and production of 58.3 Bcfe. Our revenues were bolstered by oil and gas prices remaining strong and our domestic production for 2004 increasing to 42.1 Bcfe or by 25% compared to 2003. We continued to focus our efforts and capital throughout the year on infrastructure improvements, increased production and the development of long-lived reserves in the Lake Washington and AWP Olmos areas. Our net production in Lake Washington for the fourth quarter of 2004 almost doubled as compared to the same period in 2003, averaging approximately 12,900 net barrels of oil equivalent per day in the fourth quarter of 2004, compared to approximately 6,900 net barrels of oil equivalent per day for the same period in 2003. During 2004, capital expenditures were also used for development in our other domestic core areas. New Zealand accounted for 16.3 Bcfe of production in 2004, a 16% decrease from production in the same period in 2003. Natural gas production in New Zealand declined primarily due to natural production declines in our TAWN properties. The TAWN gas contract was renegotiated to lower the total contract quantity and deliverability rates, and we anticipate meeting these revised contracted volumes. There is no penalty if the fields are unable to produce the minimum contracted volumes under the TAWN gas contract. New Zealand natural gas and natural gas liquids ("NGL") contracts are denominated in the New Zealand dollar, which has significantly strengthened during the last several years against the U.S. dollar. Our production costs were up in 2004 predominantly because of increased production in Lake Washington, higher severance taxes due to increased domestic revenues, and currency exchange rates in New Zealand. Our general and administrative expenses increased in 2004 primarily due to an increase in costs related to our on going compliance efforts with the Sarbanes-Oxley Act, and to increased salaries and benefits. Our debt to PV-10 ratio decreased to 18% at December 31, 2004 compared to 22% at December 31, 2003, due to higher crude oil and natural gas prices, which have increased our PV-10 value. Our debt to capitalization ratio was 43% at December 31, 2004 compared to 46% at year-end 2003, as debt levels increased slightly in 2004 but were offset by the increase in retained earnings as a result of current year profit. In June 2004, we repurchased $32.1 million of our 10-1/4% senior subordinated notes due 2009 through a tender offer. In July 2004, we repurchased $0.5 million of our 10-1/4% notes at the close of the tender offer. On August 1, 2004, we redeemed the remaining $92.5 million of these notes in accordance with our redemption rights under the indenture governing these notes. In 2004, we recorded approximately $9.5 million of debt retirement costs related to the repurchase of these notes. The redemption of these 10-1/4% notes lowered our effective interest rate. Year-end 2004 proved reserves of 799.8 Bcfe, representing a 3% decline for the year, were 49% crude oil, 40% natural gas and 11% NGLs, compared to year-end 2003 proved reserves of 820.4 Bcfe, which were 47% crude oil, 41% natural gas and 12% NGLs. Proved developed reserves remained essentially the same at 56% of total reserves at year-end 2004, compared to 59% the previous year. Domestic proved reserves increased at year-end 2004 to 652.7 Bcfe, driven by the acquisition of reserves in December 2004 in the Bay de Chene and Cote Blanche Island fields, which were predominantly proved undeveloped. Proved reserves in New Zealand decreased to 147.1 Bcfe at year-end 2004, primarily attributable to 2004 production and slight downward revisions in the Manutahi and upper Tariki Sands. In 2004 we focused our drilling activity, both domestically and in New Zealand, on proved undeveloped locations that helped maximize production in a high-price environment, but which also resulted in smaller additions to proved reserves. Results of Operations -- Years Ended 2004, 2003, and 2002 Revenues. Our revenues in 2004 increased by 49% compared to revenues in 2003, and our revenues in 2003 increased by 39% compared to 2002 revenues due primarily to increases in oil and natural gas prices in each successive year and increases in production from our Lake Washington area. Revenues from our oil and gas sales 23 comprised substantially all of total revenues for 2004 and 2003, and 94% of total revenues for 2002. Crude oil production comprised 49% of our production volumes in 2004, 38% in 2003, and 31% in 2002. Natural gas production comprised 41% of our production volumes in 2004, 53% in 2003, and 55% in 2002. Domestic production comprised 72% of our total production volumes in 2004, 64% in 2003, and 69% in 2002. The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2004, 2003, and 2002: Oil and Gas Oil and Gas Sales Sales Volume (In millions) (Bcfe) ----------------------------- ----------------------- Area 2004 2003 2002 2004 2003 2002 - ---- -------- -------- -------- ----- ----- ----- AWP Olmos................$ 49.9 $ 43.7 $ 33.1 9.0 8.4 10.9 Brookeland............... 18.0 16.4 11.9 3.4 3.9 4.1 Lake Washington.......... 152.3 59.5 18.5 23.2 12.1 4.4 Masters Creek............ 21.0 25.7 32.3 3.7 5.7 9.7 Other.................... 17.5 18.9 16.3 2.8 3.7 5.2 -------- -------- -------- ----- ---- ---- Total Domestic........$ 258.7 $ 164.2 $ 112.1 42.1 33.8 34.3 Rimu/Kauri............... 24.5 11.6 4.0 5.3 3.3 1.5 TAWN..................... 28.1 35.2 25.1 11.0 16.1 14.0 -------- -------- -------- ----- ---- ---- Total New Zealand.....$ 52.6 $ 46.8 $ 29.1 16.3 19.4 15.5 -------- -------- -------- ----- ---- ---- Total...................$ 311.3 $ 211.0 $ 141.2 58.3 53.2 49.8 ======== ======== ======== ===== ==== ==== Oil and gas sales in 2004 increased by 48%, or $100.3 million, from the level of those revenues for 2003, and our net sales volumes in 2004 increased by 10%, or 5.2 Bcfe, over net sales volumes in 2003. Average prices for oil increased to $40.24 per Bbl in 2004 from $29.89 per Bbl in 2003. Average natural gas prices increased to $4.12 per Mcf in 2004 from $3.42 per Mcf in 2003. Average NGL prices increased to $22.52 per Bbl in 2004 from $17.60 per Bbl in 2003. In 2004, our $100.3 million increase in oil, NGL, and natural gas sales resulted from: o Price variances that had a $70.6 million favorable impact on sales, of which $48.9 million was attributable to the 35% increase in average oil prices received, $16.6 million was attributable to the 20% increase in natural gas prices and $5.1 million was attributable to the 28% increase in NGL prices; and o Volume variances that had a $29.7 million favorable impact on sales, with $40.4 million of increases attributable to the 1.4 million Bbl increase in oil sales volumes and $3.8 million to the 217,000 Bbl increase in NGL sales volumes, offset by a decrease of $14.5 million due to the 4.3 Bcf decrease in natural gas sales volumes primarily from our TAWN area in New Zealand. Oil and gas sales in 2003 increased by 49%, or $69.8 million, from the level of those revenues for 2002, and our net sales volumes in 2003 increased by 7%, or 3.4 Bcfe, over net sales volumes in 2002. Average prices for oil increased to $29.89 per Bbl in 2003 from $24.52 per Bbl in 2002. Average natural gas prices increased to $3.42 per Mcf in 2003 from $2.30 per Mcf in 2002. Average NGL prices increased to $17.60 per Bbl in 2003 from $12.82 per Bbl in 2002. In 2003, our $69.8 million increase in oil, NGL, and natural gas sales resulted from: o Price variances that had a $59.0 million favorable impact on sales, of which $31.4 million was attributable to the 49% increase in average natural gas prices and $27.6 million was attributable to the 32% increase in average combined oil and NGL prices; and o Volume variances that had a $10.8 million favorable impact on sales, with $8.8 million of the increases attributable to the 422,000 Bbl increase in oil and NGL sales volumes, and $2.0 million to the 0.9 Bcf increase in natural gas sales volumes. 24 The following table provides additional information regarding our quarterly oil and gas sales:
Sales Volume Average Sales Price Natural Oil NGL Gas Combined Oil NGL Gas ------- --------- --------- ---------- ------- ------- ------- (MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf) 2002: First.................... 594 351 6.6 12.3 $ 19.21 $ 10.83 $ 1.72 Second................... 673 329 6.7 12.7 $ 25.11 $ 12.52 $ 2.60 Third.................... 683 225 6.7 12.2 $ 26.17 $ 13.58 $ 2.32 Fourth................... 647 269 7.1 12.6 $ 27.00 $ 15.25 $ 2.55 ------- --------- --------- ---------- Total................. 2,597 1,174 27.1 49.8 $ 24.52 $ 12.82 $ 2.30 ======= ========= ========= ========== 2003: First.................... 690 174 7.6 12.9 $ 32.73 $ 21.90 $ 3.71 Second................... 822 211 7.1 13.3 $ 27.97 $ 15.81 $ 3.47 Third.................... 917 247 6.7 13.6 $ 29.24 $ 16.81 $ 3.17 Fourth................... 941 191 6.6 13.4 $ 30.10 $ 16.71 $ 3.29 ------- --------- --------- ---------- Total................. 3,370 823 28.0 53.2 $ 29.89 $ 17.60 $ 3.42 ======= ========= ========= ========== 2004: First.................... 1,124 277 5.9 14.3 $ 34.14 $ 22.30 $ 3.64 Second................... 1,142 269 5.8 14.3 $ 37.24 $ 18.84 $ 4.19 Third.................... 1,076 251 6.0 13.9 $ 41.99 $ 23.33 $ 3.97 Fourth................... 1,380 243 6.1 15.9 $ 46.33 $ 26.01 $ 4.67 ------- --------- --------- ---------- Total................. 4,722 1,040 23.7 58.3 $ 40.24 $ 22.52 $ 4.12 ======= ========= ========= ==========
Costs and Expenses. Our expenses in 2004 increased $50.7 million, or 32%, compared to 2003 expenses. The majority of the increase was due to an $18.5 million increase in DD&A, an $11.4 million increase in severance and other taxes, and a $7.4 million increase in lease operating costs, all of which are primarily due to increased production volumes and oil and gas commodity prices in 2004. We also recorded $9.5 million of debt retirement costs in 2004. Our expenses in 2003 increased $26.6 million, or 20%, compared to 2002 expenses. The majority of the increase was due to a $4.9 million increase in lease operating costs, a $6.5 million increase in severance and other taxes, and a $6.8 million increase in DD&A, all of which increased as our production volumes and revenues increased in 2003. Our 2004 general and administrative expenses, net, increased $3.7 million, or 26%, from the level of such expenses in 2003, while 2003 general and administrative expenses, net, increased $3.5 million, or 33%, over 2002 levels. The increase in both 2004 and 2003 were primarily due to compliance with the Sarbanes-Oxley Act, increased salaries and burdens, and our increased activities in New Zealand. In 2004, Sarbanes-Oxley Act compliance costs, including internal and external costs, totaled $2.2 million.. The increase in 2003 was also due to a reduction in reimbursements from partnerships that we managed as almost all of the partnerships have been liquidated, along with an increase in franchise tax expense. For the years 2004, 2003, and 2002, our capitalized general and administrative costs totaled $13.1 million, $11.5 million, and $10.7 million, respectively. Our net general and administrative expenses per Mcfe produced increased to $0.30 per Mcfe in 2004 from $0.27 per Mcfe in 2003 and $0.21 per Mcfe in 2002. The portion of supervision fees recorded as a reduction to general and administrative expenses was $5.8 million for 2004, $3.6 million for 2003, and $3.1 million for 2002. DD&A increased $18.5 million, or 29%, in 2004 from 2003 levels, while 2003 DD&A increased $6.8 million, or 12%, from 2002 levels. Domestically, DD&A increased $17.6 million in 2004 due to increases in the depletable oil and gas property base, higher production in the 2004 period and slightly lower reserve volumes. In New Zealand, DD&A increased by $0.9 million in 2004 due to increases in the depletable oil and gas property base along with lower reserve volumes, offset by lower production in the 2004 period. In 2003, our domestic DD&A increased by $1.0 million due to increases in the depletable oil and gas property base, offset by slightly lower production in the 2003 period and higher reserve volumes that were added primarily through our Lake Washington activities. Our New Zealand DD&A increased by $5.8 million in 2003 due to increased production in the 2003 period. Our DD&A rate per Mcfe of production was $1.40 in 2004, $1.19 in 2003, and $1.13 in 2002, resulting from increases in per unit cost of reserves additions. We recorded $0.7 million and $0.9 million of accretions to our asset retirement obligation in 2004 and 2003, respectively. 25 Our lease operating costs per Mcfe produced were $0.71 in 2004, $0.64 in 2003 and $0.58 in 2002. There were no supervision fees recorded as a reduction to production costs in 2004, while there were $1.5 million in 2003 and $2.1 million in 2002. Our lease operating costs in 2004 increased $7.4 million, or 22%, over the level of such expenses in 2003, while 2003 costs increased $4.9 million, or 17% over 2002. Approximately $6.2 million of the increase in lease operating costs during 2004 was related to our domestic operations, which increased primarily due to increased compression and chemical costs in Lake Washington resulting from higher production from our Lake Washington area along with the reduction of 2003 expense of $1.5 million from supervision fees. Our lease operating cost in New Zealand increased in 2004 by $1.2 million due to the continued development of our Rimu/Kauri area and the increased currency exchange rate of the New Zealand dollar as compared to the U.S. dollar. Approximately $4.2 million of the increase in 2003 was due to our New Zealand operations as production increased over 2002 levels. Severance and other taxes increased $11.4 million, or 60% over 2003 levels, while in 2003 these taxes increased $6.5 million, or 51% over 2002 levels. The increase was due primarily to higher commodity prices and increased Lake Washington and Rimu/Kauri production in each of the periods. Severance taxes on oil in Louisiana are 12.5% of oil sales, which is higher than the other states where we have production. As our percentage of oil production in Louisiana increases, the overall percentage of severance costs to sales also increases. Severance and other taxes, as a percentage of oil and gas sales, were approximately 9.8%, 9.0% and 8.9% in 2004, 2003 and 2002, respectively. Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004, including amortization of debt issuance costs, totaled $6.2 million in 2004. Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in April 2002, including amortization of debt issuance costs, totaled $19.2 million in 2004, $19.1 million in 2003 and $13.5 million in 2002. Interest expense on our 10-1/4% senior subordinated notes issued in August 1999 and repurchased and retired in 2004, including amortization of debt issuance costs, totaled $7.4 million in 2004, and $13.2 million in both 2003 and 2002. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.5 million in 2004, $1.6 million in 2003, and $3.6 million in 2002. Other interest cost was $0.3 million in 2003. Our total interest cost in 2004 was $34.2 million, of which $6.5 million was capitalized. Our total interest cost in 2003 was $34.2 million, of which $6.8 million was capitalized. Our total interest cost in 2002 was $30.3 million, of which $7.0 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase of interest expense in 2004 was due to lower capitalized interest than in 2003. The increase in interest expense in 2003 was attributed to the replacement of our bank borrowings in April 2002 with our 9-3/8% senior subordinated notes due 2012 with a longer repayment term but a higher interest rate. In 2004, we incurred $9.5 million of debt retirement costs related to the repurchase and redemption of our 10-1/4% senior subordinated notes due 2009. The costs were comprised of approximately $6.5 million of premiums paid to repurchase the notes, $2.2 million to write-off unamortized debt issuance costs, $0.6 million to write-off unamortized debt discount and approximately $0.2 million of other costs. The overall effective tax rate was 32.5% in both 2004 and 2003 and 35.2% in 2002. The effective tax rate for 2004 was lower than the statutory tax rates primarily due to reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation, along with favorable corrections to tax basis amounts discovered while preparing the prior year's tax returns. These amounts were partially offset by higher deferred state income taxes. Income tax expense in 2003 includes a reduction of approximately $1.3 million from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax. This amount was partially offset by higher domestic state income taxes and other items. As discussed in Note 1 to the consolidated financial statements, we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which was recorded as a cumulative effect of change in accounting principle in the 2003 consolidated statement of income. Net Income. Our net income in 2004 of $68.5 million was 129% higher than our 2003 net income of $29.9 million due to higher commodity prices and increased production. Our net income in 2003 of $29.9 million was 151% higher than our 2002 net income of $11.9 million due to higher commodity prices and increased production. 26 Contractual Commitments and Obligations Our contractual commitments for the next five years and thereafter as of December 31, 2004 are as follows:
2005 2006 2007 2008 2009 Thereafter Total -------- -------- ------- ------- ------- ---------- ---------- (In thousands) Non-cancelable operating leases(1).....$ 2,476 $ 2,559 $ 2,519 $ 2,472 $ 2,342 $ 13,025 $ 25,393 Asset retirement obligation(2)......... 463 515 515 515 515 15,116 17,639 Drilling rigs and seismic.............. 4,355 -- -- -- -- -- 4,355 7-5/8% senior notes due 2011(3)........ -- -- -- -- -- 150,000 150,000 9-3/8% senior subordinated notes due 2012(3).......................... -- -- -- -- -- 200,000 200,000 Credit facility(4)..................... -- -- -- 7,500 -- -- 7,500 -------- -- -- ------- ------ ---------- ---------- Total................................$ 7,294 $ 3,074 $ 3,034 $10,487 $ 2,857 $ 378,141 $ 404,887 ======== ======== ======= ======= ======= ========== ==========
(1) Our office lease in Houston, Texas extends until 2015. (2) Amounts shown by year are the fair values at December 31, 2004. (3) Amounts do not include the interest obligation, which is paid semiannually. (4) The credit facility expires in October 2008 and these amounts exclude a $0.8 million standby letter of credit outstanding under this facility. Commodity Price Trends and Uncertainties Oil and natural gas prices historically have been volatile and are expected to continue to be volatile in the future. The price of oil has increased over the last two years and is currently significantly higher when compared to longer-term historical prices. Factors such as worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by OPEC, and fluctuating currency exchange rates can cause wide fluctuations in the price of oil. Domestic natural gas prices continue to remain high when compared to longer-term historical prices. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas. Such factors are beyond our control. 27 Liquidity and Capital Resources During 2004, we largely relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009 to fund capital expenditures of $171.1 million and acquisitions of $27.2 million. During 2003, we relied upon our net cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of non-core properties and equipment of $10.2 million to fund capital expenditures of $144.5 million. Net Cash Provided by Operating Activities. For 2004, our net cash provided by operating activities was $182.6 million, representing a 65% increase as compared to $110.8 million generated during 2003. The $71.8 million increase in 2004 was primarily due to an increase of $100.3 million in oil and gas sales, attributable to higher commodity prices and production, offset in part by higher lease operating costs due to higher domestic production and severance taxes as a result of higher commodity prices in 2004. In 2003, net cash provided by operating activities increased by 55% to $110.8 million, as compared to $71.6 million in 2002. The 2003 increase of $39.2 million was primarily due to an increase of oil and gas sales of $69.8 million due to higher commodity prices and production. Accounts Receivable. Included in the "Accounts receivable" balance, which totaled $39.0 million and $27.4 million at December 31, 2004 and 2003, respectively, on the accompanying balance sheets, is approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2002 and 2001 that have been disputed since early 2003. As a result of the dispute, we did not record a receivable with regard to any 2003 disputed volumes and our contract governing these sales expired in 2003. We assess the collectibility of accounts receivable and, based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2004 and 2003, we had an allowance for doubtful accounts of $0.5 million. The allowance for doubtful accounts has been deducted from the total "Accounts receivable" balances on the accompanying consolidated balance sheets. Sarbanes-Oxley Compliance Costs. We have incurred substantial costs to comply with the Sarbanes-Oxley Act of 2002. These expenditures have reduced our net cash provided by operating activities in each of the last two years. In 2004, Sarbanes-Oxley Act compliance costs, including internal and external costs, totaled $2.2 million and are reflected in "General and administrative, net" on the accompanying statements of income. We expect the costs of Sarbanes-Oxley compliance to decrease from 2004 levels in future years. Existing Credit Facility. We had $7.5 million in borrowings under our bank credit facility at December 31, 2004, and $15.9 million in outstanding borrowings at December 31, 2003. Our bank credit facility at December 31, 2004 consisted of a $400.0 million revolving line of credit with a $250.0 million borrowing base. The borrowing base is re-determined at least every six months and was reaffirmed by our bank group at $250.0 million, effective November 1, 2004. In June 2004, we renewed this credit facility, increasing the facility amount to $400.0 million from $300.0 million and extending its expiration to October 1, 2008 from October 1, 2005. We maintained the commitment amount at $150.0 million, which amount was set at our request effective May 9, 2003. Under the terms of our bank credit facility, we can increase this commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. Our revolving credit facility includes, among other restrictions that changed somewhat as the facility was renewed and extended, requirements to maintain certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt. We are in compliance with the provisions of this agreement. Our access to funds from our credit facility is not restricted under any "material adverse condition" clause, a clause that is common for credit agreements to include. A "material adverse condition" clause can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have an adverse or material effect on our operations, financial condition, prospects or properties, and would impair our ability to make timely debt repayments. Our credit facility includes covenants that require us to report events or conditions having a material adverse effect on our financial condition. The obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect. 28 Working Capital. Our working capital improved from a deficit of $35.9 million at December 31, 2003, to a deficit of $14.2 million at December 31, 2004. The improvement primarily resulted from a decrease in accrued capital costs due to a reduction in our drilling activities at year-end 2004 in comparison with year-end 2003 activity, along with an increase in accounts receivable for oil and gas sales due to higher sales volumes and commodity prices. Repurchase of 10-1/4% Senior Subordinated Notes Due 2009. In June 2004, we repurchased $32.1 million of our 10-1/4 senior subordinated notes due 2009 pursuant to a tender offer, and recorded debt retirement costs of $2.7 million related to this repurchase. In July 2004, we repurchased approximately $0.5 million of these notes, and as of August 1, 2004, we redeemed the remaining $92.5 million of these notes. We have recorded a total of $9.5 million in debt retirement costs related to the total repurchase of these notes. Debt Maturities. Our credit facility extends until October 1, 2008. Our $150.0 million of 7-5/8% senior notes mature July 15, 2011, and our $200.0 million of 9-3/8% senior subordinated notes mature May 1, 2012. Capital Expenditures. We relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, and proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009, to fund capital expenditures of $171.1 million and acquisitions of $27.2 million. Our total capital expenditures of approximately $198.3 million in 2004included: Domestic expenditures of $162.5 million as follows: o $87.7 million for drilling and developmental activity costs, predominantly in our Lake Washington area; o $31.8 million on property acquisitions, including $27.2 million to acquire properties in the Bay de Chene and Cote Blanche Island fields; o $28.7 million of domestic prospect costs, principally prospect leasehold, Lake Washington three-dimensional seismic activity, and geological costs of unproved prospects; o $9.9 million on exploratory drilling, mainly in our Lake Washington area; o $2.5 million primarily for a field office building, computer equipment, software, furniture, and fixtures; o $1.3 million on field compression facilities; and o $0.6 million on gas processing plants in the Brookeland and Masters Creek areas. New Zealand expenditures of $35.8 million as follows: o $26.7 million for drilling costs and developmental activity costs, predominantly in our Rimu/Kauri area; o $7.0 million on prospect costs, principally prospect leasehold, seismic and geological costs of unproved properties; o $1.2 million on gas processing plants; o $0.7 million on exploratory drilling; and o $0.2 million for computer equipment, software, furniture, and fixtures. We have spent considerable time and capital in 2004 and 2003 on significant facility capacity upgrades in the Lake Washington field to increase facility capacity to approximately 20,000 barrels per day for crude oil, up from 9,000 barrels per day capacity in the first quarter of 2003. We have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility. 29 We successfully completed 51 of 66 wells in 2004, for a success rate of 77%. Domestically, we completed 37 of 44 development wells for a success rate of 84% and completed four of ten exploration wells. A total of 30 wells were drilled in the Lake Washington area, of which 21 were completed, and 15 wells were drilled in the AWP Olmos area, of which 13 were completed. In New Zealand, we completed 10 of 12 wells, consisting of four Kauri sand wells drilled, five of six Manutahi sand wells, and the Tariki-D1 well. Our 2005 capital expenditure budget is $200 million to $220 million, net of $5 million to $15 million of dispositions and excluding any acquisitions. Approximately 80% of the budget is targeted for domestic activities, primarily in South Louisiana, with about 20% planned for activities in New Zealand. Approximately $15 million to $20 million of the 2005 budget will be focused on activity in the newly acquired properties in Bay de Chene and Cote Blanche Island fields. The $5 million to $15 million of dispositions relate to non-core properties planned for later in 2005. We expect that our 2005 capital expenditures will begin at the low end of the range, and depending on commodity prices and operational performance, they may increase to the high end of the range during the course of the year. We anticipate 2005 capital expenditures to approximate our cash flows provided from operating activities during 2005, similar to 2004. For 2005, we are targeting total production and proved reserves to increase 7% to 12% over the 2004 levels. Our capital expenditures were approximately $144.5 million in 2003 and $155.2 million in 2002. During 2003, we relied upon our net cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of non-core properties and equipment of $10.2 million to fund capital expenditures of $144.5 million. During 2002, we principally relied upon cash provided by operating activities of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million of 9-3/8% senior subordinated notes due 2012, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund capital expenditures of $155.2 million. Our capital expenditures in 2003 of approximately $144.5 million included: Domestic activities of $114.4 million as follows: o $57.0 million on drilling and developmental activities, primarily in our Lake Washington area; o $25.9 million for the construction of production and surface facilities, mainly in our Lake Washington area; o $11.9 million on exploratory drilling, primarily in our Lake Washington area; o $11.4 million on domestic prospect costs, principally leasehold, seismic, and geological costs; o $4.4 million on field compression facilities; o $2.0 million for producing property acquisitions; o $0.9 million for fixed assets; and o $0.9 million on gas processing plants in the Brookeland and Masters Creek areas. New Zealand activities of $30.1 million as follows: o $15.1 million on developmental activities primarily to further delineate the Rimu/Kauri area; o $6.4 million on prospect costs; o $5.7 million on gas processing plants; o $2.3 million for exploratory drilling mainly for the Tuihu exploratory well; o $0.3 million on producing properties acquisitions; and 30 o $0.3 million for fixed assets. In 2003, we participated in drilling 63 domestic development wells and eight domestic exploratory wells, of which 53 development wells and five exploratory wells were completed. In New Zealand we drilled and completed three development wells and drilled one unsuccessful exploratory well. Income Tax Regulations The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ. We do not believe the recently enacted American Jobs Creation Act of 2004 will have a material impact on our financial position or cash flow from operations in the near-term. New Accounting Principles In January 2003, the FASB issued Interpretation No. 46 (Revised December 2003) ("FIN 46R"), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 consolidated financial statements (the "Interpretation"). The Interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model - the variable interest model; which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The Interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities ("VIEs") are covered by the Interpretation and are to be evaluated for consolidation based on their variable interests. These provisions applied immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs, nor do we have variable interests in special purpose entities. The adoption of this interpretation had no impact on our financial position or results of operations. In September and November 2004, the EITF discussed a proposed framework for addressing when a limited partnership should be consolidated by its general partner, EITF Issue 04-5. The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership, and therefore should consolidate the limited partnership. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (b) substantive participating rights. The EITF reached a tentative conclusion on the circumstances in which either kick-out rights or protective rights would be considered substantive and preclude consolidation by the general partner and what limited partner's rights would be considered participating rights that would preclude consolidation by the general partner. The EITF tentatively concluded that for kick out rights to be considered substantive, the conditions specified in paragraph B20 of FIN 46R should be met. With regard to the definition of participating rights that would preclude consolidation by the general partner, the EITF concluded that the definition of those rights should be consistent with those in EITF Issue 96-16. The EITF also reached a tentative conclusion on the transition for Issue 04-05. We do not believe this EITF will have a material impact on our consolidated financial statements because we believe our limited partners have substantive kick-out rights under paragraph B20 of FIN 46R. In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the fourth quarter of 2004, undiscounted abandonment cost for future wells, not recorded at the present time but needed to develop the proved reserves in existence at the present time, should be included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing DD&A. The effect of including undiscounted abandonment costs of future wells to the undiscounted cost of oil and gas properties will increase depletion expense in future periods, however, we currently do not believe such increases will be material. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee share-based payments, including grants of employee stock options, to be recognized in the financial 31 statements based on their fair values. SFAS No. 123 discontinues the ability to account for these equity instruments under the intrinsic value method as described in APB Opinion No. 25. SFAS No. 123R requires the use of an option pricing model for estimating fair value, which is amortized to expense over the service periods. The requirements of SFAS No. 123R are effective for fiscal periods beginning after June 15, 2005. SFAS No. 123R permits public companies to adopt its requirements using one of two methods: o A "modified prospective" method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123R for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the adoption date of SFAS No. 123R that remain unvested on the adoption date. o A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. We have elected to adopt the provisions of SFAS No. 123R on July 1, 2005 using the modified prospective method. As permitted by Statement 123, the Company currently accounts for share-based payments to employees using APB Opinion No. 25's intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of Statement No. 123R's fair value method is expected to have a significant impact on our result of operations. However, it will have no impact on our overall financial position. We currently use the Black-Scholes formula to estimate the value of stock options granted to employees and expect to continue to use this acceptable option valuation model upon the required adoption of SFAS No. 123R. The significance of the impact of adoption will depend on levels of share-based payments granted in the future. However, had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share in "Stock Based Compensation," under Note 1 to our accompanying consolidated financial statements. Statement No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. While the Company cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of excess tax deductions recognized were $2.0 million, $0.2 million, and $0.3 million in 2004, 2003 and 2002, respectively. These deductions resulted in an increase in operating cash flows, however, due to the Company's net operating tax loss position, deferred income taxes were reduced rather than actual cash taxes paid. Proved Oil and Gas Reserves. At year-end 2004, our total proved reserves were 799.8 Bcfe with a PV-10 Value of $2.0 billion. In 2004, our proved natural gas reserves decreased 17.6 Bcf, or 5%, while our proved oil reserves increased 1.8 MMBbl, or 3%, and our NGL reserves decreased 2.3 MMBbl, or 14%, for a total equivalent decrease of 20.5 Bcfe, or 3%. In 2003, our proved natural gas reserves increased by 9.1 Bcf, or 3%, while our proved oil reserves increased by 11.4 MMBbl, or 22%, and our NGL reserves decreased by 1.0 MMBbl, or 6%, for a total equivalent increase of 71.0 Bcfe, or 9%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 7.2 Bcfe (all of which was domestic) of proved reserves in 2004, 105.6 Bcfe (36.1 Bcfe of which came from New Zealand) in 2003, and 83.9 Bcfe (15.9 Bcfe of which came from New Zealand) in 2002. Through acquisitions we added 43.4 Bcfe of proved reserves in 2004, 0.5 Bcfe in 2003, and 74.2 Bcfe in 2002. At year-end 2004, 56% of our total proved reserves were proved developed, compared with 59% at year-end 2003 and 60% at year-end 2002. The PV-10 Value of our total proved reserves increased 31% from the PV-10 Value at year-end 2003. Gas prices increased in 2004 to $5.16 per Mcf from $4.56 per Mcf at year-end 2003, compared to $3.49 per Mcf at year-end 2002. Oil prices increased in 2004 to $41.07 per Bbl from $30.16 per Bbl at year-end 2003, compared to $29.27 in 2002. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant, for that year's reserve calculation, throughout the life of the properties. Subsequent changes to such year-end oil and gas prices could have a significant impact on the calculated PV-10 Value. 32 Critical Accounting Policies The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 1 to the consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates that were used to prepare these financial statements include: o the estimated quantities of proved oil and natural gas reserves used to compute depletion of our properties and the related present value of estimated future net cash flows from these properties, o accruals related to oil and gas production and revenues, capital expenditures and lease operating and severance tax expenses, o the estimated future cost and timing of asset retirement obligations, and o estimates made in our income tax calculations. While we are not aware of any significant revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs. Property and Equipment. We follow the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2004, 2003, and 2002, such internal costs capitalized totaled $13.1 million, $11.5 million, and $10.7 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2004, 2003, and 2002, capitalized interest on unproved properties totaled $6.5 million, $6.8 million, and $7.0 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred. Full-CostCeiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, including future abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Test"). Our hedges at year-end 2004 consisted mainly of natural gas and crude oil price floors with strike prices lower than the period end price and thus did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis for those countries with proved reserves. The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. 33 Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future. Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. During 2004, 2003 and 2002, we recognized net losses of $1.3 million, $2.8 million and $0.2 million, respectively, relating to our derivative activities. This activity is recorded in "Price-risk management and other, net" on the accompanying statements of income. At December 31, 2004, the Company had recorded $0.5 million, net of taxes of $0.3 million, of derivative losses in "Accumulated other comprehensive income (loss), net of income tax" on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in "Price-risk management and other, net" for 2004, 2003 and 2002 was not material. We expect to reclassify all amounts currently held in "Accumulated other comprehensive income (loss), net of income tax" into the statement of income within the next twelve months when the forecasted sale of hedged production occurs. At December 31, 2004, we had in place price floors in effect through the December 2004 contract month for natural gas, these cover a portion of our domestic natural gas production for January 2005 to December 2005. The natural gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted average floor price of $5.83 per MMBtu. Our natural gas price floors in place at December 31, 2004 are expected to cover approximately 30% to 35% of our domestic natural gas production from January 2005 to December 2005. At December 31, 2004, we also had in place crude oil price floors in effect through the March 2005 contract month, which cover a portion our domestic crude oil production for January 2005 to March 2005. The crude oil price floors cover notional volumes of 216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil price floors in place at December 31, 2004 are expected to cover approximately 15% to 20% of our domestic crude oil production from January 2005 to March 2005. When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas and crude oil production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in "Accumulated other comprehensive income (loss), net of income tax." When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from "Accumulated other comprehensive income (loss), net of income tax" and recorded in "Price-risk management and other, net" on the consolidated statement of income. The fair value of our derivatives are computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2004, was $1.8 million and is recognized on the balance sheet in "Other current assets." From January 2005 to the date of this filing, we entered into additional natural gas price floors covering contract periods April 2005 to October 2005, which cover our natural gas production for April 2005 to October 2005. Notional volumes are 1,300,000 MMBtu at a weighted average floor price of $5.73 per MMBtu. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of commodity risk. 34 Stock Based Compensation. We have two stock-based compensation plans, which are described more fully in Note 6 to our accompanying consolidated financial statements. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. We issued restricted stock for the first time in 2004, and recorded expense related to these shares of less than $0.1 million in "General and administrative, net" on the accompanying statements of income. No stock-based employee compensation cost is reflected in net income for employee stock options, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities' cash flows, commodity pricing, environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, predominantly a portion of our "Deferred income taxes" and a portion of our "Asset Retirement Obligation" on the accompanying balance sheet. For accounts other than "Deferred income taxes," as the currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in "Price-risk management and other, net" on the accompanying statements of income. We recognize transaction gains and losses on "Deferred income taxes" in "Provision for Income Taxes" on the accompanying statement of income. Related-Party Transactions We have been the operator of a number of properties owned by affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships totaled approximately $0.2 million in 2004 and 2003 and approximately $0.3 million in 2002, and are recorded as reductions of general and administrative, net. We also have been reimbursed for administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $0.2 million, $0.4 million, and $1.0 million in 2004, 2003, and 2002, respectively, and are recorded as reductions in general and administrative, net. Included in "Accounts receivable" and "Accounts payable and accrued liabilities" on the accompanying balance sheets, is less than $0.1 million and $1.1 million, respectively, in receivables from and payables to the partnerships at December 31, 2004. We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled by the sister of the Company's Chairman and Vice Chairman of the Board. The sister and brother-in-law of Messrs. A. E. Swift and V. Swift also own a substantial majority of Tec-Com. In 2004, 2003 and 2002, we paid approximately $0.4 million per year to Tec-Com for such services pursuant to the terms of the contract between the parties. The contract was renewed June 30, 2004 on substantially the same terms and expires June 30, 2007. We believe that the terms of this contract are consistent with third party arrangements that provide similar services. As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee's charter. Other Factors Affecting Our Business and Financial Results Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices would adversely affect our financial results. Our future financial condition, results of operations, and the value of our oil and natural gas properties depend primarily upon market prices for oil and natural gas. Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. The recent record high oil and natural gas prices may not continue and could drop precipitously in a short period of time. The prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, worldwide economic conditions, weather conditions, import prices, political conditions in major oil producing regions, especially the Middle East, and actions taken by OPEC. A significant decrease in price levels for an extended period would negatively affect us in several ways: 35 o our cash flow would be reduced, decreasing funds available for capital expenditures employed to increase production or replace reserves; o certain reserves would no longer be economic to produce, leading to both lower cash flow and proved reserves; o our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserve values, reducing our liquidity and possibly requiring mandatory loan repayments; and o access to other sources of capital, such as equity or long term debt markets, could be severely limited or unavailable in a low price environment. Consequently, our revenues and profitability would suffer. Our level of debt could reduce our financial flexibility, and we currently have the ability to incur substantially more debt, including secured debt. As of December 31, 2004, our total debt comprised approximately 43% of our total capitalization. Although our bank credit facility and indentures limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, we will be permitted to incur significant additional indebtedness, including secured indebtedness, in the future if specified conditions are satisfied. All borrowings under our bank credit facility are effectively senior to our outstanding 7-5/8% senior notes and 9-3/8% senior subordinated notes to the extent of the value of the collateral securing those borrowings. Our current level of indebtedness: o will require us to dedicate a substantial portion of our cash flow to the payment of interest; o will subject us to a higher financial risk in an economic downturn due to substantial debt service costs; o may limit our ability to obtain financing or raise equity capital in the future; and o may place us at a competitive disadvantage to the extent that we are more highly leveraged than some of our peers. Higher levels of indebtedness would increase these risks. Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations. The quantities and values of our proved reserves included in this report are only estimates and subject to numerous uncertainties. Estimates by other engineers might differ materially. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserve reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of net cash flows from our oil and natural gas reserves. At December 31, 2004, approximately 44% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur. 36 If we cannot replace our reserves, our revenues and financial condition will suffer. Unless we successfully replace our reserves, our long- term production will decline, which could result in lower revenues and cash flow. When oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to drill and replace our reserves and an increased need to draw on our bank credit facility. Even if we have the capital to drill, unsuccessful wells can hurt our efforts to replace reserves. Additionally, lower oil and natural gas prices can have the effect of lowering our reserve estimates and the number of economically viable prospects that we have to drill. Drilling wells is speculative and capital intensive. Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of: o environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater and shoreline contamination; o abnormally pressured formations; o mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse; o fires and explosions; o personal injuries and death; and o natural disasters. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition. We are exposed to the risk of fluctuations in foreign currencies, primarily the New Zealand dollar. Fluctuations in rates between the New Zealand dollar and U.S. dollar impact our financial results from our New Zealand subsidiaries since we have receivables, liabilities, and natural gas and NGL sales contracts denominated in New Zealand dollars. We do not hedge against the risks associated with fluctuations in exchange rates. Although we may use hedging techniques in the future, we may not be able to eliminate or reduce the effects of currency fluctuations. As a result, exchange rate fluctuations could have an adverse impact on our operating results. We have incurred a write-down of the carrying values of our properties in the past and could incur additional 37 write-downs in the future. Under the full cost method of accounting, SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and gas properties on a country-by-country basis for possible write-down or impairment. Under these rules, capitalized costs of proved reserves may not exceed a ceiling calculated at the present value of estimated future net revenues from those proved reserves, determined using a 10% per year discount and unescalated prices in effect as of the end of each fiscal quarter. Capital costs in excess of the ceiling must be permanently written down. We recorded an after-tax, non-cash charge during the fourth quarter of 2001 of $63.5 million. This write-down resulted in a charge to earnings and a reduction of stockholders' equity, but did not impact our cash flow from operating activities. If commodity prices decline or if we have significant downward reserve revisions, we could incur additional write-downs in the future. Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile. To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us. Reserves on acquired properties may not meet our expectations, and we may be unable to identify liabilities associated with acquired properties or obtain protection from sellers against associated liabilities. Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property's production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except through the transferor. In many instances, title opinions are not obtained if, in our judgment, it would be uneconomical or impractical to do so. Losses may result from title defects or from defects in the assignment of leasehold rights. While our current operations are primarily in Louisiana, Texas, and New Zealand, we may pursue acquisitions of properties located in other geographic areas, which would decrease our geographical concentration, and could also be in areas in which we have no or limited experience. In addition, our assessment of acquired properties may not reveal all existing or potential problems or liabilities, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of acquired properties in addition to the risk that the properties may not perform in accordance with our expectations. Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities, if at all, to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. In addition, a variety of factors, including geological and market-related, can cause a well to become uneconomical or only marginally economical. For example, if oil and natural gas prices are 38 much lower after we complete a well than when we identified it as a prospect, the completed well may not yield commercially viable quantities. Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and expose us to risk of financial loss. We enter into hedging transactions for our oil and natural gas production to reduce exposure to fluctuations in the price of oil and natural gas, primarily to protect against declines in prices. Our hedges at year-end 2004 consisted of mainly natural gas price floors with strike prices lower than the period end prices. Our hedging transactions have also consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions as well as crude oil price floors. We intend to continue to enter into these types of hedging transactions in the foreseeable future. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions other than floors may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Additionally, hedging transactions other than floors may expose us to cash margin requirements. We may have difficulty competing for oil and gas properties or supplies. We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for the equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Our business depends on oil and natural gas transportation facilities, some of which are owned by others. The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. Governmental laws and regulations are costly and stringent, especially those relating to environmental protection. Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operations. Changes in or additions to environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could have a material adverse effect our operations and financial position. Our operations outside of the United States could also be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may 39 include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior owners or operators, closure, and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations. 40 Forward-Looking Statements The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as "plan," "future," "estimate," "expect," "budget," "predict," "anticipate," "projected," "should," "believe," or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management's current plans, expectations, estimates, and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and, therefore, actual results may differ materially. Among the factors that could cause actual results to differ materially are: volatility in oil and natural gas prices, internationally or in the United States; availability of services and supplies; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed in this report and set forth from time to time in our other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year. 41 Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of such pricing volatility are expected to continue. Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. Below is a description of the financial instruments we have utilized to hedge our exposure to price risk. o Price Floors - At December 31, 2004, we had in place price floors in effect through the December 2005 contract month for natural gas, these cover a portion of our domestic natural gas production for January 2005 to December 2005. The natural gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted average floor price of $5.83 per MMBtu. Our natural gas price floors in place at December 31, 2004 are expected to cover approximately 30% to 35% of our domestic natural gas production from January 2005 to December 2005. At December 31, 2004, we also had in place crude oil price floors in effect through the March 2005 contract month, which cover a portion of our domestic crude oil production for January 2005 to March 2005. The crude oil price floors cover notional volumes of 216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil price floors in place at December 31, 2004 are expected to cover approximately 15% to 20% of our domestic crude oil production from January 2005 to March 2005. The fair value of these instruments at December 31, 2004, was $1.8 million and is recognized on the accompanying balance sheet in "Other current assets." There are no additional cash outflows for these price floors, as the cash premium was paid at inception of the hedge. The maximum loss that could be sustained from these price floors in 2005 would be their fair value at December 31, 2004 of $1.8 million. o New Zealand Gas Contracts - All of our gas production in New Zealand is sold under long-term, fixed-price contracts denominated in New Zealand Dollars. These contracts protect against price volatility, and our revenue from these contracts will vary only due to production fluctuations and foreign exchange rates. Interest Rate Risk. Our senior notes and senior subordinated notes both have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At December 31, 2003, we had $7.5 million in outstanding borrowings under our credit facility, which bears a floating rate of interest and therefore is susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank's base rate would constitute 53 basis points and would reduce 2005 cash flows by less than $0.1 million based on the December 31, 2004 level of borrowing. Income Tax Carryforwards. We had significant federal and state net operating loss and capital loss carryforwards at December 31, 2004. The Company has not recorded a valuation allowance against the deferred tax assets attributable to these carryovers at December 31, 2004, as management estimates that it is more likely than not that these assets will be fully utilized before they expire except for a $0.5 million valuation allowance against the capital loss carryforward, as detailed in Note 3 of the accompanying consolidated financial statements. Significant changes in estimates caused by changes in oil and gas prices, production levels, capital expenditures, and other variables could impact the Company's ability to utilize the carryover amounts. If we are not able to use our carryforwards, our results of operations and cash flows will be negatively impacted. Financial Instruments and Debt Maturities. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2004 and 2003, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2004 and 2003, the fair values of our senior subordinated notes due 2012 were $224.0 million, or 112.0% of face value, and $218.0 million, or 109% of face value, respectively. Based upon quoted market prices as of December 31, 2004, the fair value of our senior notes due 2011 was $162.4 million, or 108.25% of face value. 42 The carrying value of our senior subordinated notes due 2012 was $200.0 million at December 31 for both 2004 and 2003. The carrying value of our senior notes due 2011 was $150.0 million at December 31, 2004. Foreign Currency Risk. We are exposed to the risk of fluctuations in foreign currencies, most notably the New Zealand Dollar. Fluctuations in rates between the New Zealand Dollar and U.S. Dollar may impact our financial results from our New Zealand subsidiaries since we have receivables, liabilities, natural gas and NGL sales contracts, and New Zealand income tax calculations, all denominated in New Zealand Dollars. We use the U.S. Dollar as our functional currency in New Zealand and because of this, our results of operations, cash flows and effective tax rate are impacted from fluctuations between the U.S. Dollar and the New Zealand Dollar. Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and seek to minimize exposure to any one customer where other customers are readily available. Due to availability of other purchasers, we do not believe the loss of any single oil or gas customer would have a material adverse effect on our results of operations. 43 Item 8. Financial Statements and Supplementary Data Management's Report on Internal Control Over Financial Reporting...........................................45 Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting...................................46 Report of Independent Registered Public Accounting Firm...................47 Consolidated Balance Sheets...............................................48 Consolidated Statements of Income.........................................49 Consolidated Statements of Stockholders' Equity...........................50 Consolidated Statements of Cash Flows.....................................51 Notes to Consolidated Financial Statements................................52 1. Summary of Significant Accounting Policies..........................52 2. Earnings Per Share..................................................61 3. Provision for Income Taxes..........................................61 4. Long-Term Debt .....................................................65 5. Commitments and Contingencies.......................................68 6. Stockholders' Equity................................................68 7. Related-Party Transactions..........................................69 8. Foreign Activities..................................................70 9. Acquisitions and Dispositions.......................................70 10. Segment Information.................................................71 Supplemental Information (Unaudited).....................................73 44 Management's Report on Internal Control over Financial Reporting Management of Swift Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with U. S. generally accepted accounting principles. Management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2004. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control--Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2004. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on management's assessment of the Company's internal control over financial reporting as of December 31, 2004. That report, which expresses unqualified opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, appears on the following page. 45 Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting The Board of Directors and Stockholders of Swift Energy Company We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Swift Energy Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Swift Energy Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assessment that Swift Energy Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Swift Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Swift Energy Company as of December 31, 2004 and 2003, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2004 and our report dated March 11, 2005 expressed an unqualified opinion thereon. ERNST & YOUNG LLP Houston, Texas March 11, 2005 46 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders of Swift Energy Company We have audited the accompanying consolidated balance sheets of Swift Energy Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2004. 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 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Swift Energy Company and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. As discussed in Note 1 to the consolidated financial statements, in 2003 the Company changed its method of accounting for asset retirement obligations. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Swift Energy Company's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2005 expressed an unqualified opinion thereon. ERNST & YOUNG LLP Houston, Texas March 11, 2005 47 Consolidated Balance Sheets Swift Energy Company and Subsidiaries
December 31, ASSETS 2004 2003 ----------------- ----------------- Current Assets: Cash and cash equivalents $ 4,920,118 $ 1,066,280 Accounts receivable- Oil and gas sales 38,029,409 26,082,650 Joint interest owners 1,013,938 1,350,707 Other current assets 10,422,531 4,961,320 ----------------- ----------------- Total Current Assets 54,385,996 33,460,957 ----------------- ----------------- Property and Equipment: Oil and gas, using full-cost accounting Proved properties 1,479,681,903 1,305,110,582 Unproved properties 80,121,509 67,557,969 ----------------- ----------------- 1,559,803,412 1,372,668,551 Furniture, fixtures, and other equipment 12,820,622 10,602,786 ----------------- ----------------- 1,572,624,034 1,383,271,337 Less - Accumulated depreciation, depletion, and amortization (649,185,874) (567,464,334) ----------------- ----------------- 923,438,160 815,807,003 ----------------- ----------------- Other Assets: Deferred income taxes 1,666,058 1,905,909 Debt issuance costs 9,148,977 8,015,575 Restricted assets 1,933,956 649,100 ----------------- ----------------- 12,748,991 10,570,584 ----------------- ----------------- $ 990,573,147 $ 859,838,544 ================= ================= LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 29,406,877 $ 26,247,477 Accrued capital costs 22,489,467 29,417,542 Accrued interest 9,209,192 8,748,656 Undistributed oil and gas revenues 7,512,755 4,939,667 ----------------- ----------------- Total Current Liabilities 68,618,291 69,353,342 ----------------- ----------------- Long-Term Debt 357,500,000 340,254,783 Deferred Income Taxes 73,106,580 43,498,682 Asset Retirement Obligation 17,176,136 9,340,473 Commitments and Contingencies Stockholders' Equity: Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding --- --- Common stock, $.01 par value, 85,000,000 shares authorized, 28,570,632 and 28,011,109 shares issued, and 28,089,764 and 27,484,091 shares outstanding, respectively 285,706 280,111 Additional paid-in capital 343,536,298 334,865,204 Treasury stock held, at cost, 480,868 and 527,018 shares, respectively (6,896,245) (7,558,093) Unearned compensation (1,728,585) --- Retained earnings 138,524,301 70,073,384 Accumulated other comprehensive income (loss), net of income tax 450,665 (269,342) ----------------- ----------------- 474,172,140 397,391,264 ----------------- ----------------- $ 990,573,147 $ 859,838,544 ================= =================
See accompanying Notes to Consolidated Financial Statements. 48 Consolidated Statements of Income Swift Energy Company and Subsidiaries
Year Ended December 31, 2004 2003 2002 ----------------- ----------------- --------------- Revenues: Oil and gas sales $ 311,285,172 $ 211,032,639 $ 141,195,713 Gain on asset disposition --- --- 7,332,668 Price-risk management and other, net (1,008,398) (2,131,656) 1,441,430 ----------------- ----------------- --------------- 310,276,774 208,900,983 149,969,811 ----------------- ----------------- --------------- Costs and Expenses: General and administrative, net 17,787,125 14,097,066 10,564,849 Depreciation, depletion, and amortization 81,580,828 63,072,057 56,224,392 Accretion of asset retirement obligation 673,654 857,356 --- Lease operating cost 41,214,256 33,833,198 28,918,858 Severance and other taxes 30,401,293 19,033,604 12,578,454 Interest expense, net 27,643,108 27,268,524 23,274,969 Debt retirement cost 9,536,268 --- --- ----------------- ----------------- --------------- 208,836,532 158,161,805 131,561,522 ----------------- ----------------- --------------- Income Before Income Taxes and Change in Accounting Principle 101,440,242 50,739,178 18,408,289 Provision for Income Taxes 32,989,325 16,468,514 6,485,062 ----------------- ----------------- --------------- Income Before Change in Accounting Principle $ 68,450,917 $ 34,270,664 $ 11,923,227 Cumulative Effect of Change in Accounting Principle (net of taxes) --- 4,376,852 --- ----------------- ----------------- --------------- Net Income $ 68,450,917 $ 29,893,812 $ 11,923,227 ================= ================= =============== Per Share Amounts- Basic: Income Before Change in Accounting Principle $ 2.46 $ 1.25 $ 0.45 Change in Accounting Principle --- (0.16) --- ----------------- ----------------- --------------- Net Income $ 2.46 $ 1.09 $ 0.45 ================= ================= =============== Diluted: Income Before Change in Accounting Principle $ 2.41 $ 1.24 $ 0.45 Change in Accounting Principle --- (0.16) --- ----------------- ----------------- --------------- Net Income $ 2.41 $ 1.08 $ 0.45 ================= ================= =============== Weighted Average Shares Outstanding 27,822,413 27,357,579 26,382,906 ================= ================= ===============
See accompanying Notes to Consolidated Financial Statements. 49 Consolidated Statements of Stockholders' Equity Swift Energy Company and Subsidiaries
Accumulated Additional Other Common Paid-in Treasury Unearned Retained Comprehensive Stock (1) Capital Stock Compensation Earnings Income (Loss) Total ---------- -------------- -------------- ------------- ------------- ------------- ------------ Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ - $ 28,256,345 $ - $312,652,720 Stock issued for benefit plans (38,149 shares) 292 617,960 127,795 - - - 746,047 Stock options exercised (112,995 shares) 1,130 924,719 - - - - 925,849 Tax benefits from exercise of stock options - 281,694 - - - - 281,694 Public stock offering (1,725,000 shares) 17,250 30,465,809 - - - - 30,483,059 Employee stock purchase plan (9,801 shares) 98 122,343 - - - - 122,441 Stock issued in acquisitions (520,000 shares) 3,000 4,958,126 3,155,074 - - - 8,116,200 Comprehensive income: Net income - - - - 11,923,227 - 11,923,227 Change in fair value of cash flow hedges, net of income tax - - - - - (178,053) (178,053) ------------ Total comprehensive income - - - - - - 11,745,174 ---------- -------------- -------------- ------------- ------------- ------------- ------------ Balance, December 31, 2002 $ 278,116 $ 333,543,471 $ (8,749,922) $ - $ 40,179,572 $ (178,053) $365,073,184 ========== ============== ============== ============= ============= ============= ============ Stock issued for benefit plans (83,201 shares) 1 (408,178) 1,191,829 - - - 783,652 Stock options exercised (142,807 shares) 1,428 1,158,984 - - - - 1,160,412 Tax benefits from exercise of stock options - 156,980 - - - - 156,980 Employee stock purchase plan (56,574 shares) 566 413,947 - - - - 414,513 Comprehensive income: Net income - - - - 29,893,812 - 29,893,812 Change in fair value of cash flow hedges, net of income tax - - - - - (91,289) (91,289) ------------ Total comprehensive - - - - - - 29,802,523 income ---------- -------------- -------------- -------------- ------------- ------------- ------------ Balance, December 31, 2003 $ 280,111 $ 334,865,204 $ (7,558,093) $ - $ 70,073,384 $ (269,342) $397,391,264 ========== ============== ============== ============== ============= ============= ============ Stock issued for benefit plans (46,150 shares) - 166,298 661,848 - - - 828,146 Stock options exercised (509,105 shares) 5,091 4,260,882 - - - - 4,265,973 Tax benefits from exercise of stock options - 1,956,555 - - - - 1,956,555 Employee stock purchase plan (50,418 shares) 504 502,097 - - - - 502,601 Issuance of restricted stock - 1,785,262 - (1,785,262) - - - Amortization of restricted stock compensation - - 56,677 - - 56,677 Comprehensive income: Net income - - - - 68,450,917 - 68,450,917 Change in fair value of cash flow hedges, net of income tax - - - - - 720,007 720,007 ------------ Total comprehensive income - - - - - - 69,170,924 ---------- -------------- -------------- -------------- ------------- ------------- ------------ Balance, December 31, 2004 $ 285,706 $ 343,536,298 $ (6,896,245) $ (1,728,585) $ 138,524,301 $ 450,665 $474,172,140 =========== ============== ============== ============= ============== ============= ============
(1)$.01 par value. See accompanying Notes to Consolidated Financial Statements. 50 Consolidated Statements of Cash Flows Swift Energy Company and Subsidiaries
Year Ended December 31, ------------------------------------------------------ 2004 2003 2002 ----------------- ---------------- ---------------- Cash Flows from Operating Activities: Net income $ 68,450,917 $ 29,893,812 $ 11,923,227 Adjustments to reconcile net income to net cash provided by operating activities- Cumulative effect of change in accounting principle --- 4,376,852 --- Depreciation, depletion, and amortization 81,580,828 63,072,057 56,224,392 Accretion of asset retirement obligation 673,654 857,356 --- Deferred income taxes 32,513,325 16,332,492 6,482,724 Debt retirement cost - cash and non-cash 9,536,268 --- --- Gain on asset disposition --- --- (7,332,668) Other (435,439) 908,927 270,770 Change in assets and liabilities- (Increase) decrease in accounts receivable (11,040,543) (7,163,304) 883,419 Increase in accounts payable and accrued liabilities 843,341 2,432,111 206,163 Increase in accrued interest 460,536 116,976 2,968,287 ----------------- ---------------- ---------------- Net Cash Provided by Operating Activities 182,582,887 110,827,279 71,626,314 ----------------- ---------------- ----------------- Cash Flows from Investing Activities: Additions to property and equipment (171,095,101) (144,503,180) (103,773,337) Proceeds from the sale of property and equipment 5,058,147 10,186,970 13,256,674 Acquisition of TAWN fields --- --- (51,460,586) Acquisition of Bay de Chene and Cote Blanche Island fields (27,196,336) --- --- Net cash received as operator of oil and gas properties 3,921,673 3,073,718 4,152,645 Net cash received (distributed) as operator of partnerships 884,093 260,726 (23,241,501) Other (658,630) (71,193) (39,953) ----------------- ---------------- ----------------- Net Cash Used in Investing Activities (189,086,154) (131,052,959) (161,106,058) ----------------- ---------------- ----------------- Cash Flows from Financing Activities: Proceeds from long-term debt 150,000,000 --- 200,000,000 Payments of long-term debt (125,000,000) --- --- Net proceeds from (payments of) bank borrowings (8,400,000) 15,900,000 (134,000,000) Net proceeds from issuances of common stock 4,825,251 1,575,853 31,409,200 Payments of debt retirement costs (6,734,611) --- --- Payments of debt issuance costs (4,333,535) --- (6,262,435) ----------------- ---------------- ---------------- Net Cash Provided by Financing Activities 10,357,105 17,475,853 91,146,765 ----------------- ---------------- ---------------- Net Increase (Decrease) in Cash and Cash Equivalents $ 3,853,838 $ (2,749,827) $ 1,667,021 Cash and Cash Equivalents at Beginning of Year 1,066,280 3,816,107 2,149,086 ----------------- ---------------- ---------------- Cash and Cash Equivalents at End of Year $ 4,920,118 $ 1,066,280 $ 3,816,107 ================= ================ ================ Supplemental Disclosures of Cash Flows Information: Cash paid during year for interest, net of amounts capitalized $ 26,064,158 $ 25,763,169 $ 19,189,822 Cash paid during year for income taxes $ 476,000 $ 129,738 $ 2,500 Non-Cash Financing Activity: Issuance of common stock in acquisitions $ --- $ --- $ 8,116,200 See accompanying Notes to Consolidated Financial Statements.
51 Notes to Consolidated Financial Statements Swift Energy Company and Subsidiaries 1. Summary of Significant Accounting Policies Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company and our wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas, as well as onshore oil and natural gas reserves in New Zealand. Our investments in oil and gas limited partnerships where we are the general partner, and our undivided interests in gas processing plants, are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity's assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include: o the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there from, o accruals related to oil and gas revenues, capital expenditures and lease operating expenses, o the estimated future cost and timing of asset retirement obligations, and o estimates made in our income tax calculations. While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs. Property and Equipment. We follow the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2004, 2003, and 2002, such internal costs capitalized totaled $13.1 million, $11.5 million, and $10.7 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2004, 2003, and 2002, capitalized interest on unproved properties totaled $6.5 million, $6.8 million, and $7.0 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred. No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred. Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization of oil and gas properties by the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized 52 costs of oil and gas properties--including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties--by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependant on our production from these properties in future years. Our total amortization per Mcfe was $1.38, $1.17, and $1.11 in 2004, 2003, and 2002, respectively. Our domestic amortization per Mcfe was $1.46, $1.30, and $1.25 in 2004, 2003, and 2002, respectively. Our New Zealand amortization per Mcfe was $1.17, $0.94, and $0.80 in 2004, 2003 and 2002, respectively. Furniture, fixtures, and other equipment, held at cost, are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between three and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized. Geological and geophysical (G&G) costs incurred on developed properties are recorded in Proved Property and therefore subject to amortization. In exploration areas, G&G costs directly associated with specific unproved properties are capitalized in "Unproved properties" and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a country-by-country basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense. Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, including gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability is limited to the sum of the estimated future net revenues from proved properties, excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects ("Ceiling Test"). Our hedges at year-end 2004 consisted mainly of natural gas and crude oil price floors with strike prices lower than the period end price and thus did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis. The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future. Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Processing costs for natural gas and natural gas liquids (NGLs) that are paid in-kind are deducted from revenues. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in "Accounts payable and accrued liabilities" on the accompanying balance sheet. Natural gas balancing receivables are reported in "Other current assets" on the 53 accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2004, we did not have any material natural gas imbalances. Accounts Receivable. Included in the "Accounts receivable" balance, which totaled $39.0 million and $27.4 million at December 31, 2004 and 2003, respectively, on the accompanying balance sheets, is approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that have been disputed since early 2003. As a result of the dispute, we did not record a receivable with regard to any 2003 disputed volumes and our contract governing these sales expired in 2003. We assess the collectibility of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2004 and 2003, we had an allowance for doubtful accounts of $0.5 million. The allowance for doubtful accounts has been deducted from the total "Accounts receivable" balances on the accompanying consolidated balance sheets. Debt issuance costs. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the public offering in April 2002 of our 9-3/8% senior subordinated notes due 2012, the June 2004 extension of our bank credit facility, and the public offering in June 2004 of our 7-5/8% senior notes due 2011 were capitalized and are amortized on an effective interest basis over the life of each of the respective note offerings and credit facility. The 9-3/8% senior subordinated notes due 2012 mature on May 1, 2012, and the balance of their issuance costs at December 31, 2004, was $4.6 million, net of accumulated amortization of $1.0 million. The issuance costs associated with our revolving credit facility, which was extended in June 2004, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2004, was $0.8 million, net of accumulated amortization of $1.6 million. The 7-5/8% senior notes due 2011 mature on July 15, 2011, and the balance of their issuance costs at December 31, 2004, was $3.7 million, net of accumulated amortization of $0.2 million. The remaining $2.2 million of debt issuance costs related to the 10-1/4% senior subordinated notes due 2009 was charged to "debt retirement cost" on the accompanying statements of income when the related debt was retired in 2004. Limited Partnerships. At year-end 2004, we serve as managing general partner for six private limited partnerships, and during fiscal 2004, less than 1% of our total oil and gas sales was attributable to our interests in those partnerships. These six partnerships were formed between 1996 and 1998, and will continue to operate until their limited partners vote otherwise. Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. During 2004, 2003 and 2002, we recognized net losses of $1.3 million, $2.8 million and $0.2 million, respectively, relating to our derivative activities. This activity is recorded in "Price-risk management and other, net" on the accompanying statements of income. At December 31, 2004, the Company had recorded $0.5 million, net of taxes of $0.3 million, of derivative gains in "Accumulated other comprehensive income (loss), net of income tax" on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in "Price-risk management and other, net" for 2004, 2003 and 2002 was not material. We expect to reclassify all amounts currently held in "Accumulated other comprehensive income (loss), net of income tax" into the statement of income within the next twelve months when the forecasted sale of hedged production occurs. At December 31, 2004, we had in place price floors in effect through the December 2005 contract month for natural gas, that cover a portion of our domestic natural gas production for January 2005 to December 2005. The natural gas price floors cover notional volumes of 4,000,000 MMBtu, with a weighted average floor 54 price of $5.83 per MMBtu. Our natural gas price floors in place at December 31, 2004 are expected to cover approximately 30% to 35% of our domestic natural gas production from January 2005 to December 2005. At December 31, 2004, we also had in place crude oil price floors in effect through the March 2005 contract month, which cover a portion our domestic crude oil production for January 2005 to March 2005. The crude oil price floors cover notional volumes of 216,000 barrels, with a weighted average floor price of $37.00 per barrel. Our crude oil price floors in place at December 31, 2004 are expected to cover approximately 15% to 20% of our domestic crude oil production from January 2005 to March 2005. When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas and crude oil production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in "Accumulated other comprehensive income (loss), net of income tax." When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from "Accumulated other comprehensive income (loss), net of income tax" and recorded in "Price-risk management and other, net" on the consolidated statement of income. The fair value of our derivatives is computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2004, was $1.8 million and is recognized on the accompanying balance sheet in "Other current assets." Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to general and administrative, net based on our estimate of the costs incurred to operate the wells, with the remainder applied as a reduction to lease operating cost. Based on recent estimates, effective October 1, 2003, we began recording the supervision fee only as a reduction to general and administrative, net. The total amount of supervision fees charged to the wells we operate was $5.8 million in 2004, $5.1 million in 2003, and $5.3 million in 2002. Inventories. We value inventories at the lower of cost or market value. Cost of crude oil inventory is determined using the weighted average method and all other inventory is accounted for using the first in, first out method ("FIFO"). The major categories of inventories, which are included in "Other current assets" on the accompanying balance sheets, are shown as follows: Balance at Balance at December 31, 2004 December 31, 2003 (000's) (000's) - ------------------ ------------------ ------------------ ------------------ Materials, Supplies and Tubulars... $ 6,417 $ 2,966 Crude Oil ......................... 770 238 ------------------ ----------------- Total .................... $ 7,187 $ 3,204 ================== ================= Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. The effective tax rate for 2004 was lower than the statutory tax rates primarily due to reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation, along with favorable corrections to tax basis amounts discovered while preparing the prior year's tax returns. These amounts were partially offset by higher deferred state income taxes. Income tax expense in 2003 includes a reduction from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax. This amount was partially offset by higher deferred state income taxes and other items. The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such laws can differ. The Company is currently evaluating the impact of the recently enacted American Jobs Creation Act of 2004. We do not believe this act will have a material impact in the near-term on our financial position or cash flow from operations. Accounts Payable and Accrued Liabilities. Included in "Accounts payable and accrued liabilities," on the accompanying balance sheets, at December 31, 2004 and 2003 are liabilities of approximately $6.9 million and $11.9 million, respectively, represents the amount by which checks issued, but not presented to the Company's banks for collection, exceeded balances in the applicable bank accounts. 55 Cash and Cash Equivalents. We consider all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents. Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2004, oil and gas sales to Shell, both domestically and in New Zealand, were $149.2 million, or 48% of total oil and gas sales. During 2003, oil and gas sales to Shell, both domestically and in New Zealand, were $31.1 million, or 15% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $23.5 million, or 11% of total oil and gas sales. During 2002, oil and gas sales to Eastex Crude Company were $25.4 million, or 18% of total oil and gas sales, while sales to subsidiaries of Contact Energy in New Zealand were $14.6 million, or 10% of total oil and gas sales. Credit losses in 2004, 2003 and 2002 have been immaterial. Environmental Costs. Our operations include activities that are subject to extensive federal and state environmental regulations. Costs associated with redemption projects, which are probable and quantifiable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred. Restricted Assets. These balances include amounts deposited on plugging bonds in New Zealand, along with amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields domestically and in New Zealand. Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities cash flows, commodity pricing environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, predominantly our portion of our "Deferred income taxes" and a portion of our "Asset Retirement Obligation" on the accompanying balance sheet. For accounts other than "Deferred income taxes," as the currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in "Price-risk management and other, net" on the accompanying statements of income. We recognize transaction gains and losses on "Deferred income taxes" in "Provision for Income Taxes" on the accompanying statement of income. Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2004 and 2003, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2004 and 2003, the fair values of our senior subordinated notes due 2012 were $224.0 million , or 112.0% of face value, and $218.0 million, or 109% of face value, respectively. Based upon quoted market prices as of December 31, 2004, the fair value of our senior notes due 2011 was $162.4 million, or 108.25% of face value. The carrying value of our senior subordinated notes due 2012 was $200.0 million at December 31 for both 2004 and 2003. The carrying value of our senior notes due 2011 was $150.0 million at December 31, 2004. Reclassification of Prior Period Balances. Certain reclassifications have been made to prior period amounts to conform to the current year presentation. 56 Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow the provisions of SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2004, we recorded $0.5 million, net of taxes of $0.3 million, of derivative gains in "Accumulated other comprehensive income (loss), net of income tax" on the accompanying balance sheet. The components of accumulated other comprehensive Income (loss) and related tax effects for 2004 were as follows:
Gross Value Tax Effect Net of Tax Value ------------------- ----------------- ------------------- Other comprehensive loss at December 31, 2003 $ (420,847) $ 151,505 $ (269,342) Change in fair value of cash flow hedges 2,433,433 (890,636) 1,542,797 Effect of cash flow hedges settled during the period (1,301,758) 478,968 (822,790) ------------------- ----------------- ------------------- Other comprehensive income at December 31, 2004 $ 710,828 $ (260,163) $ 450,665 =================== ================= ===================
Total comprehensive income was $69.2 million, $29.8 million, and $11.7 million for 2004, 2003, and 2002, respectively. Stock Based Compensation. We have two stock-based compensation plans, which are described more fully in Note 6. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. We issued restricted stock to employees for the first time in 2004, and recorded expense related to these shares of less than $0.1 million in "General and administrative, net" on the accompanying statements of income. No stock-based employee compensation cost is reflected in net income for employee stock options, as all options granted under those plans had an exercise price equal to the fair market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, "Accounting for Stock-Based Compensation," our net income and earnings per share would have been adjusted to the following pro forma amounts:
2004 2003 2002 ---------------- -------------- ---------------- Net Income: As Reported $68,450,917 $29,893,812 $11,923,227 Stock-based employee compensation expense determined under fair value method for all awards, net of tax (3,557,541) (4,112,455) (4,451,799) ---------------- -------------- ---------------- Pro Forma $64,893,376 $25,781,357 $7,471,428 Basic EPS: As Reported $2.46 $1.09 $0.45 Pro Forma $2.33 $0.94 $0.28 Diluted EPS: As Reported $2.41 $1.08 $0.45 Pro Forma $2.29 $0.94 $0.27
Pro forma compensation cost reflected above may not be representative of the cost to be expected in future years. The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions in 2004, 2003, and 2002, respectively: no dividend yield; expected volatility factors of 38.6%, 34.71%, and 73.72%; risk-free interest rates of 3.59%, 4.63%, and 4.74%; and expected lives of 5.4, 7.2, and 7.4 years. We view all awards of stock compensation as a single award with an expected life equal to the average expected life of component awards and amortize the award on a straight-line basis over the life of the award. 57 Asset Retirement Obligation. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. Based on our experience and analysis of the oil and gas services industry, we have not factored a market risk premium into our asset retirement obligation. SFAS No. 143 was adopted by us effective January 1, 2003. Upon adoption of SFAS No. 143, we recorded an asset retirement obligation of $8.9 million, an addition to oil and gas properties of $2.0 million, and a non-cash charge of $4.4 million (net of $2.5 million of deferred taxes), which is recorded as a Cumulative Effect of Change in Accounting Principle. The cumulative charge to earnings took into consideration the impact of adopting SFAS No. 143 on previous full-cost ceiling tests. SFAS No. 143 is silent with respect to whether prior period ceiling tests should be reflected in the implementation entry calculation; however, management believes that any impairment on the properties should be reflected in the historical periods. Had we not considered the impact of adopting SFAS No. 143 on previous full-cost ceiling tests, the charge recognized would have been reduced. Excluding the Cumulative Effect of Change in Accounting Principle, the adoption of SFAS No. 143 reduced our 2003 net income by approximately $0.6 million, or $0.02 per diluted share. The following provides a roll-forward of our asset retirement obligation:
Asset Retirement Obligation recorded as of January 1, 2003 $ 8,934,320 Accretion expense for 2003 857,356 Liabilities incurred for new wells and facilities construction 608,166 Reductions due to sold and abandoned wells (443,391) Revisions in estimated cash flows 67,511 Increase due to currency exchange rate fluctuations 113,511 ----------------- Asset Retirement Obligation as of December 31, 2003 $ 10,137,473 ----------------- Accretion expense for 2004 673,654 Liabilities incurred for new wells and facilities construction 712,521 Liabilities incurred for Bay de Chene and Cote Blanche Island acquisitions 2,941,490 Reductions due to sold and abandoned wells (1,083,174) Revisions in estimated cash flows 4,195,474 Increase due to currency exchange rate fluctuations 61,698 ----------------- Asset Retirement Obligation as of December 31, 2004 $ 17,639,136 -----------------
At December 31, 2004 and 2003, approximately $0.5 million and $0.8 million, respectively, of our asset retirement obligation is classified as a current liability in "Accounts payable and accrued liabilities" on the accompanying consolidated balance sheets. The pro forma effect for 2002, assuming adoption of SFAS No. 143 effective January 1, 2002, would have included a non-cash charge of $3.7 million (net of $2.1 million of deferred taxes), which would have been recorded as a Cumulative Effect of Change in Accounting Principle and recognition of an asset retirement obligation of $6.2 million. The following table displays our pro forma results for the year ended December 31, 2002, had we adopted SFAS No. 143 effective January 1, 2002. Year Ended December 31, 2002 ------------------ Net Income: Actual - as reported $ 11,923,227 Pro Forma $ 7,542,383 Basic EPS: Actual - as reported $ 0.45 Pro Forma $ 0.29 Diluted EPS: Actual - as reported $ 0.45 Pro Forma $ 0.28 58 New Accounting Pronouncements. In January 2003, the FASB issued Interpretation No. 46 (Revised December 2003) ("FIN 46R"), Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 consolidated financial statements (the "Interpretation"). The Interpretation significantly changes whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model - the variable interest model; which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. The Interpretation provides guidance for determining whether an entity lacks sufficient equity or its equity holders lack adequate decision-making ability. These variable interest entities ("VIEs") are covered by the Interpretation and are to be evaluated for consolidation based on their variable interests. These provisions applied immediately to variable interests in VIEs created after January 31, 2003, and to variable interests in special purpose entities for periods ending after December 15, 2003. The provisions apply for all other types of variable interests in VIEs for periods ending after March 15, 2004. We have no variable interests in VIEs, nor do we have variable interests in special purpose entities. The adoption of this interpretation had no impact on our financial position or results of operations. In September and November 2004, the EITF discussed a proposed framework for addressing when a limited partnership should be consolidated by its general partner, EITF Issue 04-5. The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership, and therefore should consolidate the limited partnership. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (b) substantive participating rights. The EITF reached a tentative conclusion on the circumstances in which either kick-out rights or protective rights would be considered substantive and preclude consolidation by the general partner and what limited partner's rights would be considered participating rights that would preclude consolidation by the general partner. The EITF tentatively concluded that for kick out rights to be considered substantive, the conditions specified in paragraph B20 of FIN 46R should be met. With regard to the definition of participating rights that would preclude consolidation by the general partner, the EITF concluded that the definition of those rights should be consistent with those in EITF Issue 96-16. The EITF also reached a tentative conclusion on the transition for Issue 04-05. We do not believe this EITF will have a material impact on our consolidated financial statements because we believe our limited partners have substantive kick-out rights under paragraph B20 of FIN 46R. In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 (SAB 106). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the fourth quarter of 2004, undiscounted abandonment cost for future wells, not recorded at the present time but needed to develop the proved reserves in existence at the present time, should be included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing DD&A. The effect of including undiscounted abandonment costs of future wells to the undiscounted cost of oil and gas properties will increase depletion expense in future periods, however, we currently do not believe such increases will be material. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee share-based payments, including grants of employee stock options, to be recognized in the financial statements based on their fair values. SFAS No. 123 discontinues the ability to account for these equity instruments under the intrinsic value method as described in APB Opinion No. 25. SFAS No. 123R requires the use of an option pricing model for estimating fair value, which is amortized to expense over the service periods. The requirements of SFAS No. 123R are effective for fiscal periods beginning after June 15, 2005. SFAS No. 123R permits public companies to adopt its requirements using one of two methods: o A "modified prospective" method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123R for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the adoption date of SFAS No. 123R that remain unvested on the adoption date. o A "modified retrospective" method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented 59 or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures. We have elected to adopt the provisions of SFAS No. 123R on July 1, 2005 using the modified prospective method. As permitted by Statement 123, the Company currently accounts for share-based payments to employees using APB Opinion No. 25's intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of Statement No. 123R's fair value method is expected to have a significant impact on our result of operations. However, it will have no impact on our overall financial position. We currently use the Black-Scholes formula to estimate the value of stock options granted to employees and expect to continue to use this acceptable option valuation model upon the required adoption of SFAS No. 123R. The significance of the impact of adoption will depend on levels of share-based payments granted in the future. However, had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share under "Stock Based Compensation." Statement No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. While the Company cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of excess tax deductions recognized were $2.0 million, $0.2 million, and $0.3 million in 2004, 2003 and 2002, respectively. These deductions resulted in an increase in operating cash flows, however, due to the Company's net operating tax loss position, deferred income taxes were reduced rather than actual cash taxes paid. 60 2. Earnings Per Share Basic earnings per share ("Basic EPS") have been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share ("Diluted EPS") for all periods also assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Certain of our stock options that would potentially dilute Basic EPS in the future were also antidilutive for the 2004, 2003, and 2002 periods and are discussed below. The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the years ended December 31, 2004, 2003, and 2002:
2004 2003 2002 ----------------------------------- -------------------------------- -------------------------------------- Per Per Per Net Share Net Share Net Share Income Shares Amount Income Shares Amount Income Shares Amount ------------ ---------- ----------- ------------- ---------- -------- ------------- ---------- --------- Basic EPS: Net Income and Share Amounts $ 68,450,917 27,822,413 $ 2.46 $ 29,893,812 27,357,570 $ 1.09 $ 11,923,227 26,382,906 $ 0.45 Dilutive Securities: Restricted Stock -- -- -- -- -- -- Stock Options -- 524,860 -- 203,360 -- 372,700 ------------ ---------- ------------- ---------- ------------- ---------- Diluted EPS: Net Income and Assumed Share Conversions $ 68,450,917 28,347,273 $ 2.41 $ 29,893,812 27,560,930 $ 1.08 $ 11,923,227 26,755,606 $ 0.45 ============ ========== ============= ========== ============= ==========
Options to purchase approximately 3.0 million shares at an average exercise price of $18.51 were outstanding at December 31, 2004, while options to purchase 3.2 million shares at an average exercise price of $16.37 were outstanding at December 31, 2003, and options to purchase 3.0 million shares at an average exercise price of $16.64 were outstanding at December 31, 2002. Approximately 1.1 million, 1.7 million, and 1.3 million options to purchase shares were not included in the computation of Diluted EPS for the years ended December 31, 2004, 2003, and 2002, respectively, because these options were antidilutive in that the option price was greater than the average closing market price for the common shares during those periods. Employee restricted stock grants of 70,900 shares, which were issued in 2004, were not included in the computation of Diluted EPS for the year ended December 31, 2004, because these restricted stock grants were antidilutive in that the amount of future compensation expense per share recognized as proceeds in the treasury stock method was greater than the average closing market price for the common shares during that period. Other restricted stock grants of 30,000 shares, which were issued in 2004, were not included in the computation of Diluted EPS for the year ended December 31, 2004, as performance conditions surrounding the vesting of these shares had not occurred. 3. Provision for Income Taxes Income before taxes is as follows: Year Ended December 31, -------------------------------------------------- 2004 2003 2002 --------------- -------------- -------------- United States $ 86,000,508 $ 38,955,405 $ 12,889,583 Foreign 15,439,734 11,783,773 5,518,706 --------------- -------------- -------------- Total $ 101,440,242 $ 50,739,178 $ 18,408,289 =============== ============== ============== 61 The following is an analysis of the consolidated income tax provision: Year Ended December 31, ------------------------------------------------------ 2004 2003 2002 --------------- --------------- ---------------- Current $ 469,717 $ 164,284 $ 2,338 --------------- --------------- ---------------- Deferred - Domestic 31,137,643 14,386,868 4,870,239 - Foreign 1,381,965 1,917,362 1,612,485 --------------- --------------- ---------------- Total Deferred 32,519,608 16,304,230 6,482,724 --------------- --------------- ---------------- Total $ 32,989,325 $ 16,468,514 $ 6,485,062 =============== =============== ================ Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates are as follows:
2004 2003 2002 --------------- --------------- --------------- Income taxes computed at U.S. statutory rate (35%) $ 35,504,086 $ 17,758,712 $ 6,442,901 State tax provisions, net of federal benefits 1,140,499 373,992 323,902 Effect of foreign operations 317,967 (235,675) (110,374) Currency exchange impact on foreign tax calculation (2,516,120) (2,893,655) (208,688) Correction to tax basis of foreign oil and gas properties (1,378,900) --- --- Change in estimate for deferred Louisiana income taxes, net of federal benefits 858,943 1,216,105 --- --------------- --------------- --------------- Other, net (937,150) 249,035 37,321 --------------- --------------- --------------- Provision for income taxes $ 32,989,325 $ 16,468,514 $ 6,485,062 =============== =============== =============== Effective rate 32.5% 32.5% 35.2%
As noted in the above table, the most significant contributor to the difference between the federal statutory rate and the effective rate for 2004 and 2003 is attributed to currency exchange impact on the foreign income tax calculation. The Company's New Zealand subsidiaries use the U.S. Dollar as their functional currency for financial reporting purposes, but income taxes are calculated from New Zealand Dollar financial statements and re-measured into U.S. Dollars. Volatility in exchange rates creates variable results when computing income in different currencies. The most significant difference in the relative income computations for 2004 and 2003 was attributable to depreciation, depletion, and amortization (DD&A). Because of the relative strengthening of the New Zealand Dollar vs. the U.S. Dollar, the value of the tax DD&A deduction reflects the relative appreciation in the New Zealand Dollar tax basis of amortizable assets vs. the historical U.S. Dollar investment costs. As a result, taxable income (and accordingly income tax expense) computed in New Zealand Dollars and then converted to U.S. Dollars at the average exchange rates for each respective year was significantly less than net income computed in the subsidiaries' U.S. Dollar financial statements. Additionally, the deferred tax asset is revalued at the ending exchange rate for each period. This revaluation also resulted in favorable adjustments for 2004, 2003, and 2002. In aggregate, the Company recognized foreign exchange benefits to tax expense in the amounts of $2.5 million, $2.9 million, and $0.2 million for 2004, 2003, and 2002, respectively. If exchange rates remain volatile in the future significant fluctuations in the impact on the Company's effective tax rate are likely to continue. In addition to the exchange impact, the Company also had a favorable adjustment in 2004 from a correction in the tax basis of the TAWN assets. The majority of these adjustments were discovered when 62 preparing the 2002 New Zealand tax returns which were due and filed in March 2004. Additionally, the basis adjustments resulted in an increase in the acquired deferred tax asset balance of $1.1 million. The primary unfavorable differences between the federal statutory and the effective rate are attributable to state income taxes (computed net of the offsetting federal benefit), which were $1.1 million, $0.4 million and $0.3 million for 2004, 2003, and 2002, respectively. Additional, the Company recorded adjustments to the cumulative Louisiana deferred tax liability in the amounts of $0.9 million and $1.2 million during 2004 and 2003, respectively due to its increased level of business activity in Louisiana. The Company calculates its Louisiana income tax using the "apportionment" accounting method. Under apportionment accounting, total federal taxable income is allocated based on the proportional level of U.S. business activity within the state. Due to the relative increase in the Company's Louisiana activity, the Company increased its estimate of future Louisiana taxable income that will result from the reversal of prior years' timing differences. The 2004 increase was primarily due to acquisitions and development activities in Lake Washington. The 2003 increase was primarily due to development activities in Lake Washington. The New Zealand statutory rate is 33%, which resulted in differences of $0.3 million, $0.2 million, and $0.1 million for 2004, 2003, and 2002 respectively vs. the U.S. statutory rate. The 2004 favorable rate impact is more than offset by a $0.6 million accrual for taxes expected to be incurred on a planned dividend from the Company's New Zealand subsidiaries. Except for a limited dividend tied to a cost of capital computation, the Company does not compute a provision for U.S. taxes on the undistributed earnings of our New Zealand subsidiaries as management has plans to reinvest such earnings outside of the United States indefinitely. If, in the future, these earnings are distributed into the U.S. in the form of dividends or otherwise, we may be subject to U.S. income taxes and New Zealand withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable if such remittances occur. Presently, there are no foreign tax credits available to reduce the U.S. taxes on such amounts if repatriated. The Company is currently evaluating the possibility of utilizing a special one-time tax deduction relating to the repatriation of foreign earnings created by the American Jobs Creation Act of 2004. To be eligible the Company would need to develop a qualified domestic reinvestment plan. As of this date the Company has not yet completed this evaluation or developed a reinvestment plan. However, as of December 31, 2004 the Company is in a cumulative tax loss position with respect to its foreign operations. The Company believes the maximum available deduction would be limited to the 2005 taxable earnings of its foreign subsidiaries, if any. The Company will not be in a position to make a reasonable estimate until later in the year as to how much, if any, income will be available to repatriate at the reduced rate. 63 The tax effects of temporary differences representing the net deferred tax liability (asset) at December 31, 2004 and 2003, were as follows:
2004 2003 ---- ---- Deferred tax assets: Alternative minimum tax credits (Domestic) $ (2,579,399) $ (1,979,399) Carryover items (Domestic) (47,600,945) (53,006,919) Acquired deferred tax asset (Foreign) (3,407,885) (3,802,435) Carryover Items (Foreign) (37,852,559) (28,294,320) Other (Domestic) (167,475) (152,725) ------------- ------------- Total deferred tax assets $ (91,608,263) $ (87,235,798) ------------- ------------- Deferred tax liabilities Domestic oil and gas exploration and development costs $ 121,893,202 $ 98,092,129 Foreign oil and gas exploration and development costs 39,594,386 30,160,846 Scheduled dividend from foreign subsidiary 626,762 -- Other (Domestic) 934,435 575,596 ------------- ------------- Total deferred tax liabilities $ 163,048,785 $ 128,828,571 ------------- ------------- Net deferred tax liabilities $ 71,440,522 $ 41,592,773 ============= =============
The total change in the net deferred liability from 2003 to 2004 was $29.8 million. Increases in the liability were attributable to deferred tax expense of $32.5 million plus $0.4 million for the tax effect of unrealized hedging gains. Unrealized hedging gains and losses are recorded net of tax as other comprehensive income (loss) adjustments to equity. Reductions were made to the net liability for the tax benefit of stock compensation deductions of $2.0 million, which are recorded as additions to paid-in-capital, and $1.1 million for an adjustment to the foreign acquired deferred tax asset. The tax basis of the assets of Southern Petroleum (NZ) Exploration Limited ("Southern NZ") on the acquisition date exceeded the cash purchase price paid by SENZ to acquire this entity. To account for the future tax benefits of this additional basis, SENZ recorded a deferred tax asset of $4.9 million. The asset is being amortized over the period in which the tax amortization is deducted. The remaining asset value at December 31, 2003, was $3.8 million. During 2004 the deferred tax asset was increased by $1.1 million as noted previously. Amortization during 2004 was $1.5 million. The other foreign carryover asset is attributable to cumulative New Zealand net operating losses of $114.7 million. New Zealand tax net operating losses do not expire. At December 31, 2004, the Company had alternative minimum tax credits of $2.6 million that carry forward indefinitely. These credits are available to reduce future regular tax liability to the extent they exceed the alternative minimum tax otherwise due. The domestic deferred tax carryover items are attributable to expected future tax benefits in the amounts of $40.0 million for federal net operating losses, $1.6 million for State of Louisiana net operating losses and $6.0 million net for capital losses. The gross capital loss asset is $6.5 million less a $.5 million impairment. At December 31, 2004, cumulative estimated federal net operating losses were $113.9 million, which will expire between 2018 and 2023. Louisiana estimated net operating losses total $44.8 million and will expire between 2013 and 2018. The Company has not recorded any valuation allowance against the deferred tax assets attributable to net operating loss carryovers at December 31, 2004 and 2003, as management estimates that it is more likely than not that these assets will be fully utilized before they expire. Significant changes in estimates caused by changes in oil and gas prices, production levels, capital expenditures, and other variables could impact the Company's ability to utilize the carryover amounts. In 2002 we recognized a capital loss of approximately $18.6 million as the result of the liquidation of our partnerships. This loss can only be utilized to offset capital gains and will expire in 2007. The Company plans to sell one or more of its oil and gas properties during the next few years that will generate sufficient capital gains to utilize the loss carry over. To generate capital gains from these dispositions, the sales proceeds must exceed the Company's total investment in the properties. Company management has identified several 64 qualified properties that have estimated current market values well in excess of the total original costs. Management believes that it is more likely than not that the Company will fully utilize the capital loss carryover. If the Company is unable to complete the sale of these properties at the prices it has estimated to be the fair market value, then a significant portion of the capital loss carryover could expire before it is utilized. During 2004 the Company recorded a valuation allowance of $0.5 million, primarily for incremental state income tax expenses that it expects to incur as a result of the planned property dispositions. 4. Long-Term Debt Our long-term debt as of December 31, 2004 and 2003, is as follows: 2004 2003 ------------- ------------- Bank Borrowings $ 7,500,000 $ 15,900,000 10-1/4% senior subordinated notes due 2009 --- 124,354,783 7-5/8% senior notes due 2011 150,000,000 --- 9-3/8% senior subordinated notes due 2012 200,000,000 200,000,000 -------------- -------------- Long-Term Debt $ 357,500,000 $ 340,254,783 ============== ============== Bank Borrowings. At December 31, 2004, we had $7.5 million in outstanding borrowings under our $400.0 million credit facility with a syndicate of ten banks that has a borrowing base of $250.0 million and expires in October 2008. At December 31, 2003, we had $15.9 million in outstanding borrowings under our credit facility. The interest rate is either (a) the lead bank's prime rate (5.25% at December 31, 2004) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. All amounts borrowed at December 31, 2004 were at the bank's prime rate. In June 2004, we increased, renewed and extended this credit facility, increasing the facility to $400 million from $300 million and extending its expiration to October 1, 2008 from October 1, 2005. The other terms of the credit facility, such as the borrowing base amount and commitment amount, stayed largely the same. The covenants related to this credit facility changed somewhat with the extension of the facility and are discussed below. We incurred $0.4 million of debt issuance costs related to the renewal of this facility in 2004, which is included in "Debt issuance costs" on the accompanying consolidated balance sheets and will be amortized to interest expense over the life of the facility. The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $5.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $15.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt or repurchasing our 7-5/8% senior notes due 2011 or 9-3/8% senior subordinated notes due 2012. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and gas properties. We have also pledged 65% of the stock in our two New Zealand subsidiaries as collateral for this credit facility. The borrowing base is re-determined at least every six months and was reconfirmed by our bank group at $250.0 million effective November 1, 2004. We requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The next scheduled borrowing base review is in May 2005. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.5 million in 2004, $1.6 million in 2003, and $3.6 million in 2002. The amount of commitment fees included in interest expense, net was $0.5 million in 2004 and $0.6 million in both 2003 and 2002. Senior Subordinated Notes Due 2009. These notes consisted of $125.0 million of 10-1/4% senior subordinated notes due August 2009, which were issued at 99.236% of the principal amount on August 4, 1999, and were scheduled to mature on August 1, 2009. These notes were unsecured senior subordinated obligations with interest payable semiannually, on February 1 and August 1. In June 2004, we repurchased $32.1 million of these notes pursuant to a tender offer. In July 2004, we repurchased an additional $0.5 million of these notes, and as of August 1, 2004, we redeemed the remaining $92.5 million in outstanding notes. In 2004, we recorded a charge of $9.5 million related to the repurchase of these notes, which is recorded in "Debt 65 retirement costs" on the accompanying consolidated statement of income. The costs were comprised of approximately $6.5 million of premiums paid to repurchase the notes, $2.2 million to write-off unamortized debt issuance costs, $0.6 million to write-off unamortized debt discount, and approximately $0.2 million of other costs. Interest expense on the 10-1/4% senior subordinated notes due 2009, including amortization of debt issuance costs and discount, totaled $7.4 million in 2004 and $13.2 million in both 2003 and 2002. Senior Notes Due 2011. These notes consist of $150.0 million of 7-5/8% senior notes due 2011, which were issued on June 23, 2004 at 100% of the principal amount and will mature on July 15, 2011. The notes are senior unsecured obligations that rank equally with all of our existing and future senior unsecured indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank credit facility, and rank senior to all of our existing and future subordinated indebtedness. Interest on these notes is payable semi-annually on January 15 and July 15, and commenced on January 15, 2005. On or after July 15, 2008, we may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.813% of principal, declining to 100% in 2010 and thereafter. In addition, prior to July 15, 2007, we may redeem up to 35% of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 107.625% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $3.9 million of debt issuance costs related to these notes, which is included in "Debt issuance costs" on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. Upon certain changes in control of Swift Energy, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these senior notes. Interest expense on the 7-5/8% senior notes due 2011, including amortization of debt issuance costs totaled $6.2 million in 2004. Senior Subordinated Notes Due 2012. These notes consist of $200.0 million of 9-3/8% senior subordinated notes due May 2012, which were issued on April 11, 2002, and will mature on May 1, 2012. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank credit facility. Interest on these notes is payable semiannually on May 1 and November 1, with the first interest payment on November 1, 2002. On or after May 1, 2007, we may redeem these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.688% of principal, declining to 100% in 2010. In addition, prior to May 1, 2005, we may redeem up to 33.33% of these notes with the net proceeds of qualified offerings of our equity at 109.375% of the principal amount of these notes, plus accrued and unpaid interest. Upon certain changes in control of Swift Energy, each holder of these notes will have the right to require us to repurchase the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these subordinated notes due 2012. Interest expense on the 9-3/8% senior subordinated notes due 2012, including amortization of debt issuance costs totaled $19.2 million in 2004, $19.1 million in 2003 and $13.5 million in 2002. The aggregate maturities on our long-term debt are $0, $0, $0, $7.5 million, $0, and $350.0 million for 2005, 2006, 2007, 2008, 2009, and thereafter, respectively. We have capitalized interest on our unproved properties in the amount of $6.5 million, $6.8 million, and $7.0 million, in 2004, 2003, and 2002, respectively. 66 5. Commitments and Contingencies Total rental and lease expenses were $2.4 million in 2004, $2.2 million in 2003, and $1.9 million in 2002 and are included in "General and administrative, net" on our accompanying consolidated statements of income. Our remaining minimum annual obligations under non-cancelable operating lease commitments are $2.5 million for 2005, $2.6 million for 2006, $2.5 million for 2007, $2.5 million for 2008, $2.3 million in 2009, and $13.0 million thereafter or $25.4 million in the aggregate. The rental and lease expenses and remaining minimum annual obligations under non-cancelable operating lease commitments primarily relate to the lease of our office space in Houston, Texas, and in New Zealand. In the ordinary course of business, we have entered into agreements with drilling and seismic contractors for such services. The remaining commitments at December 31, 2004 for these services totaled $4.4 million and these services are expected to be provided in 2005. As of December 31, 2004, we were the managing general partner of six private limited partnerships. Because we serve as the general partner of these entities, under state partnership law we are contingently liable for the liabilities of these partnerships, which liabilities are not material for any of the periods presented in relation to the partnerships' respective assets. In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations. 6. Stockholders' Equity Common Stock. During the first quarter of 2002, we issued 1.725 million shares of common stock at a price of $18.25 per share pursuant to a public underwriting offering. Gross proceeds from this offering were $31.5 million, with issuance costs of $1.0 million. Stock-Based Compensation Plans. We have two stock option plans that awards are currently granted under, the 2001 Omnibus Stock Compensation Plan, which was adopted by our Board of Directors in February 2001 and was approved by shareholders at the 2001 annual meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for our independent directors. No further grants will be made under the 1990 Stock Compensation Plan, which was replaced by the 2001 Omnibus Stock Compensation Plan, although options remain outstanding under such plan and are accordingly included in the tables below. In addition, we have an employee stock purchase plan. Under the 2001 plan, incentive stock options and other options and awards may be granted to employees to purchase shares of common stock. Under the 1990 non-qualified plan, non-employee members of our Board of Directors are automatically granted options to purchase shares of common stock on a formula basis. Both plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Unless otherwise provided, options become exercisable for 20% of the shares on the first anniversary of the grant of the option and are exercisable for an additional 20% per year thereafter. Options granted typically expire ten years after the date of grant or earlier in the event of the optionee's separation from employment. At the time the stock options are exercised, the cash received is credited to common stock and additional paid-in capital. Options issued under this plan also include a reload feature where additional options are granted at the then current market price when mature shares of Swift Energy common stock are used to satisfy the exercise price of an existing stock option grant. When Swift Energy common stock is used to satisfy the exercise price, the net shares actually issued are reflected in the accompanying Statement of Stockholders' Equity (see note 1 to table below). We view all awards of stock compensation as a single award with an expected life equal to the average expected life of component awards and amortize the award on a straight-line basis over the life of the award. The employee stock purchase plan provides eligible employees the opportunity to acquire shares of Swift Energy common stock at a discount through payroll deductions. The plan year is from June 1 to the following May 31. The first year of the plan commenced June 1, 1993. To date, employees have been allowed to authorize payroll deductions of up to 10% of their base salary during the plan year by making an election to participate prior to the start of a plan year. The purchase price for stock acquired under the plan is 85% of the 68 lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant. Under this plan for the last three years, we have issued 50,418 shares at a price range of $9.98 to $10.83 in 2004, 56,574 shares at a price range of $6.80 to $11.85 in 2003, and 9,801 shares at a price of $12.47 in 2002. As of December 31, 2004, 245,635 shares remained available for issuance under this plan. The following is a summary of our stock options under these plans as of December 31, 2004, 2003, and 2002:
2004 2003 2002 ------------------------ ------------------------ ------------------------------ Wtd. Avg. Wtd. Avg. Wtd. Avg. Shares Exer.Price Shares Exer. Price Shares Exer. Price ------------ ---------- ----------- ----------- --------------- ------------- Options outstanding, beginning of period 3,238,611 $ 16.37 3,018,505 $ 16.64 2,639,504 $ 17.44 Options granted 415,744 $ 23.36 504,014 $ 13.20 585,055 $ 12.32 Options canceled (64,866) $ 21.85 (110,901) $ 21.02 (84,254) $ 23.37 Options exercised1 (590,821) $ 9.83 (173,007) $ 8.85 (121,800) $ 8.61 ------------ ----------- --------------- Options outstanding, end of period 2,998,668 $ 18.51 3,238,611 $ 16.37 3,018,505 $ 16.64 ============ =========== =============== Options exercisable, end of period 1,542,571 $ 17.78 1,714,789 $ 15.00 1,480,490 $ 13.71 ============ =========== =============== Options available for future grant, end of period 89,278 494,925 419,845 ============ =========== =============== Estimated weighted average fair value per share of options granted during the year $9.51 $6.93 $9.55 ============ =========== ===============
The following table summarizes information about stock options outstanding at December 31, 2004:
Options Outstanding Options Exercisable --------------------------------------- -------------------------- Range of Wtd. Avg. Exercise Number Remaining Wtd. Avg. Number Wtd. Avg. Prices Outstanding Contractual Exercise Exercisable Exercise at 12/31/04 Life Price At 12/31/04 Price ---------------- -------------- ----------- ----------- ------------- ----------- $ 7.00 to $17.99 1,723,401 6.1 $ 11.64 955,298 $ 10.76 $18.00 to $28.99 598,044 7.0 $ 23.23 169,924 $ 22.60 $29.00 to $41.00 677,223 6.2 $ 31.84 417,349 $ 31.89 -------------- ------------- $ 7.00 to $41.00 2,998,668 6.3 $ 18.51 1,542,571 $ 17.78 ============== =============
1 The option plans allow for the use of a "stock swap" in lieu of a cash exercise, under certain circumstances. The delivery of Swift Energy common stock, held by the optionee for a minimum of six months, which are considered mature shares, with a fair market value equal to the required purchase price of the shares to which the exercise relates, constitutes a valid "stock swap." Options issued under a "stock swap" also include a reload feature where additional options are granted at the then current market price when mature shares of Swift stock are used to satisfy the exercise price of an existing stock option grant. The terms of the plans provide that the mature shares delivered, as full or partial payment in a "stock swap", shall again be available for awards under the plans. The options exercised above include 81,716, 30,200 and 8,805 shares in 2004, 2003 and 2002 respectively, related to "stock swap" shares that were also reloaded. Restricted Stock. In 2004, the Company issued the rights to 70,900 shares of restricted stock to employees. These shares vest over a five-year period and remain subject to forfeiture if vesting conditions are not met. In accordance with APB Opinion No. 25, we recognize unearned compensation in connection with the grant of restricted shares equal to the fair value of our common stock on the date of grant. The fair value of these shares when issued in 2004 was approximately $25 per share, and resulted in an increase in "Additional paid-in capital" and "Unearned compensation" on the accompanying balance sheet of $1.8 million. As restricted shares vest, we reduce unearned compensation and recognize compensation expense. In 2004, we recorded expense related to these shares of less than $0.1 million in "General and administrative, net" on the accompanying statements of income. In 2004, we also issued the rights to 30,000 shares of restricted stock to non-employees. These shares vest over a two-year period and remain subject to forfeiture if performance conditions are not met within that 68 period. This issuance is accounted for under FAS No. 123 and as such a measurement date for assessing fair value of this grant has not been achieved. We recognized approximately $0.2 million of compensation cost in 2004 related to these shares. The non-employee performs work that is capitalized to unproved properties, and as such the compensation cost recognized in 2004 was recorded to "Unproved properties" on the accompanying balance sheets. Employee Stock Ownership Plan. In 1996, we established an Employee Stock Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of 21 with one year of service are participants. This plan has a five-year cliff vesting. The ESOP is designed to enable our employees to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock that has been contributed by Swift Energy. Compensation expense is recognized upon vesting when such shares are released to employees. The plan may also acquire Swift Energy common stock, purchased at fair market value. The ESOP can borrow money from Swift Energy to buy Swift Energy common stock. ESOP payouts will be paid in a lump sum or installments, and the participants generally have the choice of receiving cash or stock. At December 31, 2004, 2003, and 2002, all of the ESOP compensation was earned. Our contribution to the ESOP plan totaled $0.2 million for the years ended December 31, 2004, 2003, and 2002, and were made all in common stock, and are recorded as "General and administrative, net" on the accompanying consolidated statements of income. The shares of common stock contributed to the ESOP plan totaled 6,911, 11,870, and 18,711 shares for the 2004, 2003, and 2002 contributions, respectively. Employee Savings Plan. We have a savings plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make voluntary contributions into the 401(k) savings plan with Swift contributing on behalf of the eligible employee an amount equal to 100% of the first 2% of compensation and 75% of the next 4% of compensation based on the contributions made by the eligible employees. Our contributions to the 401(k) savings plan were $0.7 million for 2004 and $0.6 million for each of the years ended December 31, 2003 and 2002, and are recorded as "General and administrative, net" on the accompanying consolidated statements of income. The contributions in 2004, 2003, and 2002 were made all in common stock. The shares of common stock contributed to the 401(k) savings plan totaled 24,513, 34,280, and 64,490 shares for the 2004, 2003, and 2002 contributions, respectively. Common Stock Repurchase Program. In March 1997, our Board of Directors approved a common stock repurchase program that terminated as of June 30, 1999. Under this program, we spent approximately $13.3 million to acquire 927,774 shares in the open market at an average cost of $14.34 per share. At December 31, 2004, 480,868 shares remain in treasury (net of 446,906 shares used to fund ESOP, 401(k) contributions and acquisitions) with a total cost of $6.9 million and are included in "Treasury stock held, at cost" on the accompanying balance sheet. Shareholder Rights Plan. In August 1997, our board of directors declared a dividend of one preferred share purchase right on each outstanding share of Swift Energy common stock. The rights are not currently exercisable but would become exercisable if certain events occurred relating to any person or group acquiring or attempting to acquire 15% or more of our outstanding shares of common stock. Thereafter, upon certain triggers, each right not owned by an acquirer allows its holder to purchase Swift securities with a market value of two times the $150 exercise price. 7. Related-Party Transactions We have been the operator of a number of properties owned by private limited partnerships and, accordingly, charge these entities operating fees. The operating supervision fees charged to the partnerships totaled approximately $0.2 million in both 2004 and 2003, and $0.3 million in 2002, and are recorded as reductions of "General and administrative, net." We also have been reimbursed for administrative, and overhead costs incurred in conducting the business of the private limited partnerships, which totaled approximately $0.2 million, $0.4 million, and $1.0 million in 2004, 2003, and 2002, respectively, and are recorded as reductions in "General and administrative, net." Included in "Accounts receivable" and "Accounts payable and accrued liabilities" on the accompanying balance sheets, is less than $0.1 million and $1.1 million, respectively, in receivables from and payables to the partnerships at December 31, 2004. We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled by the sister of the Company's Chairman and Vice 69 Chairman of the Board. The sister and brother-in-law of Messrs. A. E. Swift and V. Swift also own a substantial majority of Tec-Com. In 2004, 2003 and 2002, we paid approximately $0.4 million per year to Tec-Com for such services pursuant to the terms of the contract between the parties. The contract was renewed June 30, 2004 on substantially the same terms and expires June 30, 2007. We believe that the terms of this contract are consistent with third party arrangements that provide similar services. As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee's charter. 8. Foreign Activities As of December 31, 2004, our gross capitalized oil and gas property costs in New Zealand totaled approximately $243.2 million. Approximately $209.8 million has been included in the "Proved properties" portion of our oil and gas properties, while $33.4 million is included as "Unproved properties." Our functional currency in New Zealand is the U.S. Dollar. Net assets of our New Zealand operations total $197.4 million at December 31, 2004. Our expenditures on oil and gas property in New Zealand were approximately $36.5 million in 2004. 9. Acquisitions and Dispositions New Zealand Through our subsidiary, Swift Energy New Zealand Limited ("SENZ"), we acquired Southern Petroleum (NZ) Exploration Limited ("Southern NZ") in January 2002 for approximately $51.4 million in cash. We allocated $36.1 million of the acquisition price to "Proved properties," $10.0 million to "Unproved properties," $4.9 million to "Deferred income taxes," and $0.4 million to "Other current assets" on our consolidated balance sheet. Southern NZ was an affiliate of Shell New Zealand and owns interests in four onshore producing oil and gas fields, hydrocarbon processing facilities, and pipelines connecting the fields and facilities to export terminals and markets. These assets fit strategically with our existing assets in New Zealand. This acquisition was accounted for by the purchase method of accounting. The revenues and expenses from these TAWN properties have been included in our consolidated statements of income from the date of acquisition forward. In conjunction with this TAWN acquisition, we granted Shell New Zealand a short-term option to acquire an undivided 25% interest in our permit 38719, which included our Rimu/Kauri areas and the Rimu Production Station. This option was not exercised and expired on May 15, 2002. In March 2002, we purchased through our subsidiary, SENZ, all of the New Zealand assets owned by Antrim for 220,000 shares of Swift Energy common stock, which we held in treasry, valued at $4.2 million and an effective date adjustment of approximately $0.5 million in cash for total consideration of $4.7 million. Antrim owned a 5% interest in permit 38719 and a 7.5% interest in permit 38716. In September 2002, we purchased through our subsidiary, SENZ, Bligh's 5% working interest in permit 38719 and 5% interest in the Rimu petroleum mining permit 38151, along wth their 3.24% working interest in the four TAWN petroleum mining licenses for 300,000 shares of Swift Energy common stock valued at $3.9 million and $2.7 million in cash for total consideration of $6.6 million. Domestic In December 2004 we acquired interests in two fields in South Louisiana, the Bay de Chene and Cote Blanche Island fields. We paid approximately $27.7 million in cash for hese interests. After taking into account internal acquisition costs of $2.8 million, our total cost was $30.5 million. We allocated $27.8 million of the acquisition price to "Proved properties," $5.1 million to "Unproved properties," we also recorded $0.5 million to "Restricted assets," and recorded a liability of $2.9 million to "Asset retirement obligation" on our accompanying consolidated balance sheet. This acquisition was accounted for by the purchase method of accounting. We made this acquisition to increase our exploration and development opportunities in South Louisiana. The revenues and expenses from these properties have been included in our accompanying consolidated statements of income from the date of acquisition forward, however, given the acquisition was in late December 2004, these amounts were immaterial. 70 Russia In 1993, we entered into a Participation Agreement with Senega, a Russian Federation joint stock company, to assist in the development and production of reserves from two fields in Western Siberia and received a 5% net profits interest. We also purchased a 1% net profits interest. Our investment in Russia was fully impaired in the third quarter of 1998. In March 2002, we received $7.5 million for our investment in Russia. Although the proceeds from sales of oil and gas properties are generally treated as a reduction of oil and gas property costs, because we had previously charged to expense all $10.8 million of cumulative costs relating to our Russian activities, this cash payment, net of transaction expenses, resulted in recognition of a $7.3 million non-recurring gain on asset disposition in the first quarter of 2002, and is included in our accompanying statements of income. 10. Segment Information The Company has two reportable segments, one domestic and one foreign, which are in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate our performance based on profit or loss from oil and gas operations before gain on asset disposition, price-risk management and other, net, general and administrative, net, interest expense, net and debt retirement costs. Our reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:
2004 -------------------------------------------- New Domestic Zealand Total ------------- ------------- ------------- Oil and gas sales $ 258,663,936 $ 52,621,236 $ 311,285,172 Costs and Expenses: Depreciation, depletion, and amortization (62,283,350) (19,297,478) (81,580,828) Accretion of asset retirement obligation (505,174) (168,480) (673,654) Lease operating cost (30,191,889) (11,022,367) (41,214,256) Severance and other taxes (26,713,592) (3,687,701) (30,401,293) ------------- ------------- ------------- Income from oil and gas operations $ 138,969,931 $ 18,445,210 $ 157,415,141 Price-risk management and other, net (1,008,398) General and administrative, net (17,787,125) Interest expense, net (27,643,108) Debt retirement costs (9,536,268) ------------- Income before Income Taxes and Change in Accounting Principle $ 101,440,242 ============= Property and Equipment, net $ 731,890,068 $ 191,548,092 $ 923,438,160 Total Assets 778,611,100 211,962,047 990,573,147 Capital Expenditures $ 162,535,617 $ 35,755,820 $ 198,291,437 ============= ============= =============
71
2003 -------------------------------------------- New Domestic Zealand Total ------------- ------------- ------------- Oil and gas sales $ 164,167,390 $ 46,865,249 $ 211,032,639 Costs and Expenses: Depreciation, depletion, and amortization (44,645,939) (18,426,118) (63,072,057) Accretion of asset retirement obligation (623,948) (233,408) (857,356) Lease operating cost (24,022,412) (9,810,786) (33,833,198) Severance and other taxes (15,290,669) (3,742,935) (19,033,604) ------------- ------------- ------------- Income from oil and gas operations $ 79,584,422 $ 14,652,002 $ 94,236,424 Price-risk management and other, net (2,131,656) General and administrative, net (14,097,066) Interest expense, net (27,268,524) ------------- Income before Income Taxes and Change in Accounting Principle $ 50,739,178 ============= Property and Equipment, net $ 641,366,888 $ 174,440,115 $ 815,807,003 Total Assets 672,721,551 187,116,993 859,838,544 Capital Expenditures $ 114,443,475 $ 30,059,705 $ 144,503,180 ============= ============= =============
2002 -------------------------------------------- New Domestic Zealand Total ------------- ------------- ------------- Oil and gas sales $ 112,065,003 $ 29,130,710 $ 141,195,713 Costs and Expenses: Depreciation, depletion, and amortization (43,660,843) (12,563,549) (56,224,392) Lease operating costs (23,308,444) (5,610,414) (28,918,858) Severance and other taxes (9,780,514) (2,797,940) (12,578,454) ------------- ------------- ------------- Income from oil and gas operations $ 35,315,202 $ 8,158,807 $ 43,474,009 Gain on asset disposition 7,332,668 Price-risk management and other, net 1,441,430 General and administrative, net (10,564,849) Interest expense, net (23,274,969) ------------- Income before Income Taxes and Change in Accounting Principle $ 18,408,289 ============= Property and Equipment, net $ 565,149,393 $ 160,360,061 $ 725,509,454 Total Assets 594,627,972 172,377,887 767,005,859 Capital Expenditures $ 59,981,376 $ 95,252,547 $ 155,233,923 ============= ============= =============
72 Supplemental Information (Unaudited) Swift Energy Company and Subsidiaries Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and gas producing activities and the related depreciation, depletion, and amortization:
Total Domestic New Zealand ===================== ================ ================= December 31, 2004: Proved oil and gas properties $ 1,479,681,903 $ 1,271,354,490 $ 208,327,413 Unproved oil and gas properties 80,121,509 46,751,416 33,370,093 --------------------- ---------------- ----------------- 1,559,803,412 1,318,105,906 241,697,506 Accumulated depreciation, depletion, and amortization (641,917,990) (590,906,014) (51,011,976) --------------------- ---------------- ----------------- Net capitalized costs $ 917,885,422 $ 727,199,892 $ 190,685,530 ===================== ================ ================= December 31, 2003: Proved oil and gas properties $ 1,305,110,582 $ 1,135,615,117 $ 169,495,465 Unproved oil and gas properties 67,557,969 31,802,621 35,755,348 --------------------- ---------------- ----------------- 1,372,668,551 1,167,417,738 205,250,813 Accumulated depreciation, depletion, and amortization (560,961,013) (529,272,658) (31,688,355) --------------------- ---------------- ----------------- Net capitalized costs $ 811,707,538 $ 638,145,080 $ 173,562,458 ===================== ================ =================
Of the $46.7 million of domestic Unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2004, excluded from the amortizable base, $30.3 million was incurred in 2004, $2.9 million was incurred in 2003, $2.5 million was incurred in 2002, and $11.1 million was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to four year time frame. Of the $33.4 million of New Zealand Unproved property costs at December 31, 2004, excluded from the amortizable base, $3.7 million was incurred in 2004, $8.3 million was incurred in 2003, $17.0 million was incurred or acquired in 2002, and $4.4 million was incurred in prior years. We expect to continue drilling in New Zealand to delineate our prospects there within a two to four year time frame. Capitalized asset retirement obligations have been included in the Proved properties as of December 31, 2004 and 2003, as we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003. 73 Costs Incurred. The following table sets forth costs incurred related to our oil and gas operations:
Year Ended December 31, 2004 ----------------------------------------------------------- Total Domestic New Zealand --------------------- ---------------- ----------------- Acquisition of proved and unproved properties $ 31,771,094 $ 31,771,094 $ -- Lease acquisitions and prospect costs 1 34,545,393 27,713,059 6,832,334 Exploration 17,430,265 16,714,982 715,283 Development 105,947,485 78,163,289 27,784,196 --------------------- ---------------- ----------------- Total acquisition, exploration, and development 2 $ 189,694,237 $ 154,362,424 $ 35,331,813 --------------------- ---------------- ----------------- Processing plants $ 1,283,515 $ 147,317 $ 1,136,198 Field compression facilities 1,028,091 1,028,091 -- --------------------- ---------------- ----------------- Total plants and facilities $ 2,311,606 $ 1,175,408 $ 1,136,198 --------------------- ---------------- ----------------- Total costs incurred 3 $ 192,005,843 $ 155,537,832 $ 36,468,011 ===================== ================ ================= Year Ended December 31, 2003 ----------------------------------------------------------- Total Domestic New Zealand --------------------- ---------------- ----------------- Acquisition of proved and unproved properties $ 1,942,868 $ 1,635,316 $ 307,552 Lease acquisitions and prospect costs 1 18,869,099 12,440,144 6,428,955 Exploration 14,467,455 11,789,700 2,677,755 Development 116,451,112 100,549,351 15,901,761 --------------------- ---------------- ----------------- Total acquisition, exploration, and development 2 $ 151,730,534 $ 126,414,511 $ 25,316,023 --------------------- ---------------- ----------------- Processing plants $ 6,192,199 $ 907,771 $ 5,284,428 Field compression facilities 3,521,522 3,521,522 -- --------------------- ---------------- ----------------- Total plants and facilities $ 9,713,721 $ 4,429,293 $ 5,284,428 --------------------- ---------------- ----------------- Total costs incurred 3 $ 161,444,255 $ 130,843,804 $ 30,600,451 ===================== ================ ================= Year Ended December 31, 2002 ----------------------------------------------------------- Total Domestic New Zealand --------------------- ---------------- ----------------- Acquisition of proved and unproved properties $ 64,229,283 $ 5,415,932 $ 58,813,351 Lease acquisitions and prospect costs 1 16,009,939 10,789,876 5,220,063 Exploration 18,395,335 7,571,215 10,824,120 Development 47,407,087 40,366,378 7,040,709 --------------------- ---------------- ----------------- Total acquisition, exploration, and development 2 $ 146,041,644 $ 64,143,401 $ 81,898,243 --------------------- ---------------- ----------------- Processing plants $ 7,845,520 $ 1,313,299 $ 6,532,221 Field compression facilities 2,251,247 2,251,247 -- --------------------- ---------------- ----------------- Total plants and facilities $ 10,096,767 $ 3,564,546 $ 6,532,221 --------------------- --------------- ----------------- Total costs incurred 3 $ 156,138,411 $ 67,707,947 $ 88,430,464 ===================== ================ =================
1 These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2004, 2003, and 2002 were $17,811,217, $20,702,276, and $23,454,234, respectively. 2 Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $13.1 million, $11.5 million, and $10.7 million in 2004, 2003, and 2002, respectively. In addition, total includes $6.5 million, $6.8 million , and $7.0 million in 2004, 2003, and 2002, respectively, of capitalized interest on unproved properties. 3 Asset retirement obligations incurred have been included in exploration, development and acquisition costs as applicable for the years ended December 31, 2004 and 2003, as we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003. 74 Results of Operations.
Year Ended December 31, 2004 -------------------------------------------------- Total Domestic New Zealand --------------- -------------- --------------- Oil and gas sales $ 311,285,172 $ 258,663,936 $ 52,621,236 Lease operating cost (41,214,256) (30,191,889) (11,022,367) Severance and other taxes (30,401,293) (26,713,592) (3,687,701) Depreciation and depletion (80,504,043) (61,478,364) (19,025,679) Accretion of asset retirement obligation (673,654) (505,174) (168,480) --------------- -------------- --------------- 158,491,926 139,774,917 18,717,009 Provision for income taxes 53,093,022 51,576,944 1,516,078 --------------- -------------- --------------- Results of producing activities $ 105,398,904 $ 88,197,973 $ 17,200,931 =============== ============== =============== Amortization per physical unit of production (equivalent Mcf of gas) $ 1.38 $ 1.46 $ 1.17 =============== ============== =============== Year Ended December 31, 2003 -------------------------------------------------- Total Domestic New Zealand ---------------- -------------- --------------- Oil and gas sales $ 211,032,639 $ 164,167,390 $ 46,865,249 Lease operating cost (33,833,198) (24,022,412) (9,810,786) Severance and other taxes (19,033,604) (15,290,669) (3,742,935) Depreciation and depletion (62,037,680) (43,818,709) (18,218,971) Accretion of asset retirement obligation (857,356) (623,948) (233,408) --------------- -------------- ---------------- 95,270,801 80,411,652 14,859,149 Provision for income taxes 32,321,635 29,696,023 2,625,612 --------------- -------------- --------------- Results of producing activities $ 62,949,166 $ 50,715,629 $ 12,233,537 =============== ============== =============== Amortization per physical unit of production (equivalent Mcf of gas) $ 1.17 $ 1.30 $ 0.94 =============== ============== =============== Year Ended December 31, 2002 --------------------------------------------------- Total Domestic New Zealand --------------- -------------- ---------------- Oil and gas sales $ 141,195,713 $ 112,065,003 $ 29,130,710 Lease operating cost (28,918,858) (23,308,444) (5,610,414) Severance and other taxes (12,578,454) (9,780,514) (2,797,940) Depreciation and depletion (55,254,467) (42,807,364) (12,447,103) --------------- -------------- --------------- 44,443,934 36,168,681 8,275,253 Provision for income taxes 15,860,064 13,129,231 2,730,833 --------------- -------------- --------------- Results of producing activities $ 28,583,870 $ 23,039,450 $ 5,544,420 =============== ============== =============== Amortization per physical unit of production (equivalent Mcf of gas) $ 1.11 $ 1.25 $ 0.80 =============== ============== ===============
These results of operations do not include the losses from our hedging activities of $1.3 million, $2.8 million, and $0.2 million for 2004, 2003 and 2002, respectively. Our lease operating costs per Mcfe produced were $0.71 in 2004, $0.64 in 2003, and $0.58 in 2002. The accretion of asset retirement obligation has been included in the 2004 and 2003 periods, as we adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" effective January 1, 2003. We used our effective tax rate in each country to compute the provision for income taxes in each year presented. 75 Supplemental Reserve Information. The following information presents estimates of our proved oil and gas reserves. Reserves were determined by us and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy has audited 100% of our proved reserves. Gruy's audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy's audit was based upon review of production histories and other geological, economic, and engineering data provided by Swift. Where Gruy had material disagreements with Swift reserve estimates, we revised our estimates to be in agreement. Gruy's report dated January 27, 2005, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2004, and includes definitions and assumptions that served as the basis for the audit of proved reserves and future net cash flows. Such definitions and assumptions should be referred to in connection with the following information: Estimates of Proved Reserves
Total Domestic New Zealand ------------------------- ---------------------------- ------------------------ Oil, NGL, Oil, NGL, Oil, NGL, and and and Natural Gas Condensate Natural Gas Condensate Natural Gas Condensate (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) ------------ ----------- ------------- ----------- ----------- ----------- Proved reserves as of December 31, 2001 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903 Revisions of previous estimates 1 (29,972,714) 5,298,439 (29,470,419) 8,675,082 (502,295) (3,376,643) Purchases of minerals in place 51,940,044 3,711,948 226,245 24,207 51,713,799 3,687,741 Sales of minerals in place (3,839,124) (464,490) (3,839,124) (464,490) -- -- Extensions, discoveries, and other additions 10,822,919 12,180,558 197,919 11,304,782 10,625,000 875,776 Production (27,131,578) (3,770,128) (15,780,059) (3,074,674) (11,351,519) (695,454) ------------ ----------- ------------- ----------- ----------- ----------- Proved reserves as of December 31, 2002 326,731,672 70,438,963 239,824,062 59,029,640 86,907,610 11,409,323 Revisions of previous estimates 1 (6,445,114) 4,975,920 (1,418,312) 3,497,022 (5,026,802) 1,478,898 Purchases of minerals in place 273,623 35,472 273,623 35,472 -- -- Sales of minerals in place (3,984,209) (228,505) (3,984,209) (228,505) -- -- Extensions, discoveries, and other additions 47,231,609 9,730,665 21,370,151 8,018,766 25,861,458 1,711,899 Production (28,002,719) (4,192,612) (13,744,040) (3,336,702) (14,258,679) (855,910) ------------ ------------ ------------- ------------ ----------- ----------- Proved reserves as of December 31, 2003 335,804,862 80,759,903 242,321,275 67,015,693 93,483,587 13,744,210 Revisions of previous estimates 1 (3,306,705) (1,117,715) (1,619,531) 695,274 (1,687,174) (1,812,989) Purchases of minerals in place 9,808,953 5,602,508 9,808,953 5,602,508 -- -- Sales of minerals in place (2,524,760) (44,803) (2,524,760) (44,803) -- -- Extensions, discoveries, and other additions 2,205,670 830,111 2,205,670 830,111 -- -- Production (23,741,726) (5,762,796) (12,299,772) (4,959,740) (11,441,954) (803,056) ------------ ----------- ------------- ----------- ----------- ----------- Proved reserves as of December 31, 2004 318,246,294 80,267,208 237,891,835 69,139,043 80,354,459 11,128,165 ============ =========== ============= =========== =========== =========== Proved developed reserves: 2 December 31, 2001 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432 December 31, 2002 233,514,572 35,928,395 149,731,562 26,530,112 83,783,010 9,398,283 December 31, 2003 210,119,927 45,525,366 138,173,341 38,767,983 71,946,586 6,757,383 December 31, 2004 193,310,761 42,037,852 140,549,052 36,628,873 52,761,709 5,408,979
1 Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil, NGL, and natural gas prices at each year-end. Proved reserves, as of December 31, 2004, were based upon prices in effect at year-end. Our hedges at year-end 2004 consisted of oil and natural gas price floors with strike prices mostly lower than the period end price and thus would not materially affect prices used in these calculations. The weighted average of 2004 year-end prices for total, domestic, and New Zealand were $5.16, $5.87, and $3.07 per Mcf of natural gas, $41.07, $42.21, and $33.60 per barrel of oil, and $25.48, $26.49 and $20.48 per barrel of NGL, respectively. This compares to $4.56, $5.53, and $2.04 per Mcf of natural gas, $30.16, $30.88, and $26.78 per barrel of oil, and $20.61, $21.81 and $14.10 per barrel of NGL as of December 31, 2003, for total, domestic, and New Zealand, respectively. The weighted average of 2002 year-end prices for total, domestic, and New Zealand were $3.49, $4.23, and $1.48 per Mcf of natural gas, $29.27, $29.36, and $28.80 per barrel of oil, and $16.54, $17.30, and $12.24 per barrel of NGL, respectively. 2 At December 31, 2004, 56% of our reserves were proved developed, compared to 59% at December 31, 2003, 60% at December 31, 2002, and 50% at December 31, 2001. 76 Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
Year Ended December 31, 2004 -------------------------------------------------------- Total Domestic New Zealand ---------------- ---------------- ---------------- Future gross revenues $ 4,711,060,300 $ 4,122,705,861 $ 588,354,439 Future production costs (1,029,449,670) (819,035,166) (210,414,504) Future development costs (480,093,684) (434,305,537) (45,788,147) ---------------- ---------------- ---------------- Future net cash flows before income taxes 3,201,516,946 2,869,365,158 332,151,788 Future income taxes (896,135,438) (866,598,544) (29,536,894) ---------------- ---------------- ---------------- Future net cash flows after income taxes 2,305,381,508 2,002,766,614 302,614,894 Discount at 10% per annum (840,436,013) (746,227,690) (94,208,323) ---------------- ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,464,945,495 $ 1,256,538,924 $ 208,406,571 ================ ================ ================ Year Ended December 31, 2003 -------------------------------------------------------- Total Domestic New Zealand ---------------- ---------------- ---------------- Future gross revenues $ 3,805,349,886 $ 3,279,884,680 $ 525,465,206 Future production costs (831,430,479) (678,983,441) (152,447,038) Future development costs (331,816,723) (301,874,087) (29,942,636) ---------------- ---------------- ---------------- Future net cash flows before income taxes 2,642,102,684 2,299,027,152 343,075,532 Future income taxes (729,624,048) (657,354,849) (72,269,199) ---------------- ---------------- ---------------- Future net cash flows after income taxes 1,912,478,636 1,641,672,303 270,806,333 Discount at 10% per annum (777,622,101) (678,769,827) (98,852,274) ---------------- ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,134,856,535 $ 962,902,476 $ 171,954,059 ================ ================ ================ Year Ended December 31, 2002 -------------------------------------------------------- Total Domestic New Zealand ---------------- ---------------- ---------------- Future gross revenues $ 2,990,669,570 $ 2,578,435,576 $ 412,233,994 Future production costs (720,599,745) (612,094,088) (108,505,657) Future development costs (224,792,520) (208,492,520) (16,300,000) ---------------- ---------------- ---------------- Future net cash flows before income taxes 2,045,277,305 1,757,848,968 287,428,337 Future income taxes (599,195,484) (512,966,321) (86,229,163) ---------------- ---------------- ---------------- Future net cash flows after income taxes 1,446,081,821 1,244,882,647 201,199,174 Discount at 10% per annum (609,212,030) (540,375,347) (68,836,683) ---------------- ---------------- ---------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 836,869,791 $ 704,507,300 $ 132,362,491 ================ ================ ================
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. 2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable gas price escalations are covered by contracts limited to the price we reasonably expect to receive. 3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as asset retirement obligation costs, net of salvage value, based on year-end cost estimates and the estimated effect of future income taxes. 77 4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and gas producing activities, and tax carry forwards. The estimates of cash flows and reserves quantities shown above are based on year-end oil and gas prices for each period. Our hedges at year-end 2004 consisted mainly of crude oil and natural gas price floors with strike prices lower than the period end price and thus did not materially affect prices used in these calculations. Subsequent changes to such year-end oil and gas prices could have a significant impact on discounted future net cash flows. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations using hedge adjusted prices in effect as of the period end date presented (see Note 1 to the consolidated financial statements). Application of these rules during periods of relatively low oil and gas prices, even if of short-term seasonal duration, may result in non-cash write-downs. The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates. The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31, ------------------------------------------------------- 2004 2003 2002 ----------------- ----------------- --------------- Beginning balance $ 1,134,856,535 $ 836,869,791 $ 454,557,905 ----------------- ----------------- --------------- Revisions to reserves proved in prior years-- Net changes in prices, and production costs 398,333,372 218,104,882 418,531,747 Net changes in future development costs (117,672,270) (108,603,152) (44,641,133) Net changes due to revisions in quantity estimates (12,754,357) 48,194,999 2,582,633 Accretion of discount 152,715,946 116,136,717 60,298,619 Other 49,111,385 (57,822,716) (88,675,455) ----------------- ----------------- --------------- Total revisions 469,734,076 216,010,730 348,096,411 New field discoveries and extensions, net of future production and development costs 30,609,517 243,183,114 190,461,371 Purchases of minerals in place 118,575,886 1,019,290 76,538,437 Sales of minerals in place (7,339,601) (13,660,012) (5,769,642) Sales of oil and gas produced, net of production costs (239,669,623) (158,165,836) (99,698,403) Previously estimated development costs incurred 98,924,021 77,404,994 48,752,814 Net change in income taxes (140,745,316) (67,805,536) (176,069,102) ----------------- ----------------- ---------------- Net change in standardized measure of discounted future net cash flows 330,088,960 297,986,744 382,311,886 ----------------- ----------------- --------------- Ending balance $ 1,464,945,495 $ 1,134,856,535 $ 836,869,791 ================= ================= ===============
78 Quarterly Data (Unaudited). The following table presents summarized quarterly financial information for the years ended December 31, 2003 and 2004:
Income Before Income Taxes, Income Basic EPS Diluted EPS and Before Income Before Income Before Basic Diluted Change in Change in Change In Change In EPS EPS Accounting Accounting Net Accounting Accounting Net Net Revenues Principle Principle Income Principle Principle Income Income ------------ ------------ ------------ ------------ ---------------- ----------------- -------- --------- 2003: First $ 53,499,993 $ 16,223,744 $ 10,484,937 $ 6,108,085 $ 0.38 $ 0.38 $ 0.22 $ 0.22 Second 50,717,529 11,073,804 7,221,426 7,221,426 0.26 0.26 0.26 0.26 Third 51,552,522 11,153,368 7,062,625 7,062,625 0.26 0.26 0.26 0.26 Fourth 53,130,939 12,288,262 9,501,676 9,501,676 0.35 0.34 0.35 0.34 ------------ ------------ ------------ ------------ Total $208,900,983 $ 50,739,178 $ 34,270,664 $ 29,893,812 $ 1.25 $ 1.24 $ 1.09 $ 1.08 ============ ============ ============ ============ 2004: First $ 65,355,730 $ 20,086,182 14,587,854 $ 14,587,854 $ 0.53 $ 0.52 $ 0.53 $ 0.52 Second 71,043,735 20,001,147 12,897,927 12,897,927 0.46 0.46 0.46 0.46 Third 74,942,751 19,472,596 14,130,717 14,130,717 0.51 0.50 0.51 0.50 Fourth 98,934,558 41,880,317 26,834,419 26,834,419 0.96 0.93 0.96 0.93 ------------ ------------ ------------ ------------ Total $310,276,774 $101,440,242 $ 68,450,917 $ 68,450,917 $ 2.46 $ 2.41 $ 2.46 $ 2.41 ============ ============ ============ ============
There were no extraordinary items in 2003 or 2004. As described in Note 4 to the consolidated financial statements, in 2004 we incurred debt retirement costs relating to the repurchase of our 10-1/4% senior subordinated notes due 2009 totaling $9.5 million. Debt retirement costs totaled $2.7 million, $6.8 million and less than $0.1 million in the second, third and fourth quarters of 2004, respectively. The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share because to do so would have been antidilutive. 79 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure We have had no changes in or disagreements with our independent accountants since our Board of Directors' June 12, 2002 appointment, based upon the recommendation of our Audit Committee, of Ernst & Young LLP as Swift's independent auditors for the fiscal year ended December 31, 2002, replacing Arthur Andersen LLP as our independent auditors. That change was reported by Swift in a Current Report on Form 8-K dated June 12, 2002, filed with the SEC on June 18, 2002. Item 9A. Controls and Procedures The Company's chief executive officer and chief financial officer have evaluated the Company's disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act") as of the end of the period covered by the report. Based on that evaluation, they have concluded that such disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company required under the Exchange Act to be disclosed in this report. There were no significant changes in the Company's internal controls that could significantly affect such controls subsequent to the date of their evaluation. Management's Report On Internal Control Over Financial Reporting as of December 31, 2004 is included in Item 8. Financial Statements and Supplementary Data. The Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting is also included in Item 8. Item 9B. Other Information None 80 PART III Item 10. Directors and Executive Officers of the Registrant The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 10, 2005, annual shareholders' meeting is incorporated herein by reference. Item 11. Executive Compensation The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 10, 2005, annual shareholders' meeting is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 10, 2005, annual shareholders' meeting is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 10, 2005, annual shareholders' meeting is incorporated herein by reference. Item 14. Principal Accountant Fees and Services The information required under Item 14 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 10, 2005, annual shareholders' meeting is incorporated by reference. 81 PART IV Item 15. Exhibits and Financial Statement Schedules (a) 1. The following consolidated financial statements of Swift Energy Company together with the report thereon of Ernst & Young LLP dated March 11, 2005, and the data contained therein are included in Item 8 hereof: Management's Report on Internal Control Over Financial Reporting..........................................45 Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting...................46 Report of Independent Registered Public Accounting Firm........47 Consolidated Balance Sheets....................................48 Consolidated Statements of Income..............................49 Consolidated Statements of Stockholders' Equity................50 Consolidated Statements of Cash Flows..........................51 Notes to Consolidated Financial Statements.....................52 2. Financial Statement Schedules Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting [None] 3. EXHIBITS 3(a).1 Amended and Restated Articles of Incorporation of Swift Energy Company. 3(b).9 Second Amended and Restated Bylaws of Swift Energy Company, as amended through November 5, 2002. 4(a).1.2 Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A., as Trustee. 4(a).2.2 First Supplemental Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A., including the form of 9 3/8% Senior Subordinated Notes due 2012. 4(a).3.12 Indenture dated as of June 23, 2004, between Swift Energy Company and Wells Fargo Bank, National Association, as Trustee. 4(a).4.12 First Supplemental Indenture dated as of June 23, 2004, between Swift Energy Company and Wells Fargo Bank, National Association, as Trustee, including the form of 7 5/8% Senior Notes. 10.1.13 Indemnity Agreement dated July 8, 1988, between Swift Energy Company and A. Earl Swift (plus schedule of other persons with whom Indemnity Agreements have been entered into). 10.2.3 + Amended and Restated Swift Energy Company 1990 Nonqualified Stock Option Plan, as of May 1997. 10.3.3 + Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as of May 1997. 10.4.4 + Amendment to the Swift Energy Company 1990 Stock Compensation Plan, as of May 9, 2002. 82 10.5.4 + Swift Energy Company 2001 Omnibus Stock Compensation Plan. 10.6.5 + Amended and Restated Employment Agreement dated as of November 15, 2000 between Swift Energy Company and A.Earl Swift. 10.7.1 + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Terry E.Swift. 10.8.1 + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and James M.Kitterman. 10.9.1 + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Bruce H. Vincent. 10.10.1 + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Joseph A. D'Amico. 10.11.1 + Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Victor R. Moran. 10.13.1 + Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Alton D. Heckaman, Jr. 10.14.5 + Fourth Amended and Restated Agreement and Release, by and between Swift Energy Company and Virgil Neil Swift, dated November 20, 2000. 10.15.14+* Employee Stock Purchase Plan 10.16 +* Description of non-employee directors' compensation arrangements. 10.17 +* Forms of agreements for grant of incentive and non-qualified stock options and forms of agreement for grant of restricted stock under Swift Energy 2001 Omnibus Stock Compensation Plan. 10.18.6 Amended and Restated Rights Agreement between Swift Energy and American Stock Transfer & Trust Company, dated March 31, 1999. 10.19.7 Amended and Restated Credit Agreement among Swift Energy Company and Bank One, N.A. as administrative agent, CIBC Inc. as syndication agent and Credit Lyonnais New York Branch and Societe Generale as documentation agents and the lenders signatory hereto dated September 28, 2001. 10.20.8 First Amendment to Amended and Restated Credit Agreement, effective January 25, 2002 among Swift Energy Company, as Borrower, Bank One, NA as Administrative Agent, CIBC Inc. as Syndication Agent, Credit Lyonnais, New York Branch as Documentation Agent, Societe Generale as Documentation Agent and The Lenders Signatory Hereto and Banc One Capital Markets, Inc. as Sole Lead Arranger and Sole Book Runner. 10.21.8 Second Amendment to Amended and Restated Credit Agreement, effective April 5, 2002 among Swift Energy Company, as Borrower, Bank One, NA as Administrative Agent, CIBC Inc. as Syndication Agent, Wells Fargo Bank (Texas), National Association as Syndication Agent, Credit Lyonnais, New York Branch as Documentation Agent, Societe Generale as Documentation Agent and The Lenders Signatory Hereto and Banc One Capital Markets, Inc. as Sole Lead Arranger and Sole Book Runner. 83 10.22.11 First Amended and Restated Credit Agreement effective as of June 29, 2004, among Swift Energy Company and Bank One, NA as Administrative Agent, Wells Fargo Bank, National Association as Syndication Agent, BNP Paribas, as Syndication Agent, Caylon, as Documentation agent, Societe Generale, as Documentation Agent and the Lenders Signatory Hereto and Banc One Capital Markets, Inc., as Sole Lead Arranger and Sole Book Runner. 10.23.10 Consulting Agreement dated as of October 13, 2003 between Swift Energy Company and Raymond O. Loen. 10.24.11 Eighth Amendment to Lease Agreement between Swift Energy Company and Greenspoint Plaza Limited Partnership dated as of June 30, 2004. 10.25+* Description of executive officers' compensation arrangements. 12 * Swift Energy Company Ratio of Earnings to Fixed Charges. 13 * Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8754. 21 * List of Subsidiaries of Swift Energy Company. 23(a) * The consent of H.J. Gruy and Associates, Inc. 23(b) * Consent of Ernst & Young LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements. 31.1 * Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 * Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32 * Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 * The summary of H.J. Gruy and Associates, Inc. report, dated January 27, 2005. - -------------------------------------------------------------------------------- 1. Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-8754. 2. Incorporated by reference from Swift Energy Company Report on Form 8-K dated April 16, 2002, File No. 1-8754. 3. Incorporated by reference from Swift Energy Company definitive proxy statement for annual shareholders meeting filed April 14, 1997, File No. 1-8754. 4. Incorporated by reference from Registration Statement No. 333-67242 on Form S-8 filed on August 10, 2001. 84 5. Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-8754. 6. Incorporated by reference from Swift Energy Company Amendment No. 1 to Form 8-A filed April 7, 1999. 7. Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended September 30-2001, Form No. 1-8754. 8. Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002, File No. 1-8754. 9. Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003. File No. 1-8754. 10. Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2003, File No. 1-8754. 11. Incorporated by reference from Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-8754. 12. Incorporated by reference from Swift Energy Company Quarterly Form 8-K filed with the SEC on June 25, 2004, File No. 1-8754. 13. Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8754. 14. Incorporated by reference from Swift Energy Company Annual Report on Form 10-K for the fiscal year ended December 31, 2002, File No. 1-8754. * Filed herewith. + Management contract or compensatory plan or arrangement. 85 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SWIFT ENERGY COMPANY By : ------------------------------ A. Earl Swift Chairman of the Board 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, Swift Energy Company, and in the capacities and on the dates indicated: Signatures Title Date ----------- ------ ----- - -------------------------- Chairman of the Board March 15, 2005 A. Earl Swift Director - -------------------------- Chief Executive Officer March 15, 2005 Terry E. Swift Executive Vice-President - -------------------------- Principal Financial Officer March 15, 2005 Alton D. Heckaman Jr. Controller - -------------------------- Principal Accounting Officer March 15, 2005 David W. Wesson 86 - ------------------------- Director March 15, 2005 G. Robert Evans - ------------------------- Director March 15, 2005 Raymond E. Galvin - ------------------------- Director March 15, 2005 Greg Matiuk - ------------------------- Director March 15, 2005 Henry C. Montgomery - ------------------------- Director March 15, 2005 Clyde W. Smith, Jr. - ------------------------- Director March 15, 2005 Virgil N. Swift - ------------------------- Director March 15, 2005 Deanna L. Cannon 87 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 EXHIBITS TO FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2004 SWIFT ENERGY COMPANY 16825 NORTHCHASE DRIVE, SUITE 400 HOUSTON, TEXAS 77060 88 EXHIBIT INDEX 10.16 Description of non-employee directors' compensation arrangements. 10.17 Forms of agreements for grant of incentive and nonqualified stock options and forms of agreement for grant of restricted stock under Swift Energy 2001 Omnibus Stock Compensation Plan. 10.25 Description of executive officers' compensation arrangements. 12 Swift Energy Company Ratio of Earnings to Fixed Charges. 21 List of Subsidiaries of Swift Energy Company. 23(a) The consent of H.J. Gruy and Associates, Inc. 23(b) Consent of Ernst & Young LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements. 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2003. 31.2 Certification of Chief Financial Officer pursuant to Section 3-2 of the Sarbanes-Oxley Act of 2002. 32 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 The summary of H.J. Gruy and Associates, Inc. report, dated January 27, 2005. 89 Exhibit 10.16 Description of Non-Employee Director Compensation Effective October 1, 2004, as a result of significantly increased duties and responsibilities for the entire Board of Directors and its committees, the cash compensation of non-employee directors was increased to a base of $40,000 payable in cash, with an additional $5,000 for serving on one or more committees of the Board of Directors, as compared to $34,750 and $ 5,000, respectively, earned per year by non-employee directors prior to that time. The Chairman of the Audit Committee will receive an additional $12,000 in cash for a minimum of four meetings annually. The Chairmen for each of the Corporate Governance and Compensation Committees will receive an additional $6,000 in cash for a minimum of two meetings annually. All of these amounts are to be paid over the course of a year in four equal installments. Since 1990, non-employee directors upon joining the Board have been entitled to receive stock options to purchase 10,000 shares of common stock, and on an annual basis on the day after the Annual Meeting of Shareholders, options to purchase an additional 5,000 shares of common stock, with each director entitled to hold options covering no more than 66,000 shares at any one time. A new director is not entitled to receive the annual grant if his or her initial grant was within 11 months of the initial grant of options. All such stock options are granted at the current market price for the Company's common stock on the date of grant. At the date of this filing, the Compensation Committee of the Board is reviewing equity compensation of non-employee board members, any changes in which would be submitted to shareholders for their approval under New York Stock Exchange rules. 90 Exhibit 10.17 INCENTIVE STOCK OPTION AGREEMENT 2001 Omnibus Stock Compensation Plan ((Date)) Grant of Options. Swift Energy Company hereby grants to ((NAME)) (the "Optionee") incentive stock options for a total of ((AMOUNT)) (((AMOUNT1>>) shares of the Company's common stock, par value of $.01 per share (the "Options"), exercisable at the price and upon the terms and conditions set forth hereinbelow, and subject to any adjustments made pursuant to Section 12 of the Plan. Approval of Counsel Required for Issuance of Common Stock. No share of Common Stock shall be issued pursuant to the exercise of the Options unless counsel for the Company shall be satisfied that such issuance will be in compliance with applicable Federal and state securities laws. Options Subject to Plan. The Options are granted as Incentive Stock Options (subject to the $100,000 per calendar year limitations contained in Section 6(j) of the Plan, as such limit may be changed by the Code) pursuant to the Company's 2001 Omnibus Stock Compensation Plan (the "Plan"), and are in all respects subject to the terms, provisions, conditions and restrictions of the Plan. A copy of the Plan is attached hereto as Exhibit A and is incorporated herein by reference. In the event of any conflict between this instrument and the Plan, the Plan shall control. Defined Terms. Except as otherwise defined herein, capitalized terms used in this instrument shall have the meanings ascribed to such terms in the Plan. Date of Grant. The Options are granted as of the date first set forth above. Exercise Price. Each Option shall have an exercise price for the related share of Common Stock of $_______, which is not less than the Fair Market Value of each share of Common Stock calculated in accordance with Section 2(j) of the Plan, or, if the Optionee is a Ten Percent Shareholder, is not less than 110% of such Fair Market Value. The exercise price is subject to adjustment pursuant to Section 12 of the Plan. Vesting of Options. The Options shall be exercisable in installments in accordance with the following table, except as otherwise provided in the Plan: Date First Exercisable Number of Options DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) ---------- Total: ((NUMBER1)) Option Period. Each Option may be exercised at any time between the date at which it becomes exercisable and ten years from the Date of Grant, or five years from the Date of Grant if Optionee is a Ten Percent Shareholder, inclusive of 91 such dates, except that in the event of the Optionee's death, or his or her Disability (defined under Section 2 of the Plan), or if the Optionee's employment by the Company is terminated for any reason, or if there is a Change in Control of the Company, then the provisions of Sections 10(a), 10(c) and 13 of the Plan, respectively, shall govern the option period. Method of Exercise. The Options are exercisable in accordance with the procedures, but subject to all conditions and restrictions, set forth in the Plan. Limitation on Exercise. The aggregate Fair Market Value (determined as of the date first set forth above) of the number of shares of Common Stock with respect to which Options are exercisable for the first time by the Optionee during any calendar year as "Incentive Stock Options" under Section 422 of the code shall not exceed $100,000, or such other limit as may be required by the Code. Transferability. The Options are not assignable or transferable except by will or the laws of descent and distribution. SWIFT ENERGY COMPANY By:_________________________________ The Optionee acknowledges receipt of a copy of the Plan, represents that he is familiar with the terms and provisions thereof, and hereby accepts the Options evidenced hereby subject to all the terms, provisions, conditions and restrictions of the Plan. ---------------------------------------- Printed Name: ___________________________ 92 NONQUALIFIED STOCK OPTION AGREEMENT 2001 Omnibus Stock Compensation Plan Date of Grant Grant of Options. Swift Energy Company hereby grants to ((NAME)) (the "Optionee") NonQualified stock options for a total of ((AMOUNT)) (((AMOUNT1))) shares of the Company's common stock, par value of $.01 per share (the "Options"), exercisable at the price and upon the terms and conditions set forth hereinbelow, and subject to any adjustments made pursuant to Section 12 of the Plan. Approval of Counsel Required for Issuance of Common Stock. No share of Common Stock shall be issued pursuant to the exercise of the Options unless counsel for the Company shall be satisfied that such issuance will be in compliance with applicable Federal and state securities laws. Options Subject to Plan. The Options are granted as NonQualified Stock Options pursuant to the Company's 2001 Omnibus Stock Compensation Plan (the "Plan"), and are in all respects subject to the terms, provisions, conditions and restrictions of the Plan. A copy of the Plan is available upon request and is incorporated herein by reference. In the event of any conflict between this instrument and the Plan, the Plan shall control. Defined Terms. Except as otherwise defined herein, capitalized terms used in this instrument shall have the meanings ascribed to such terms in the Plan. Date of Grant. The Options are granted as of the date first set forth above. Exercise Price. Each Option shall have an exercise price for the related share of Common Stock of $________, which is not less than the Fair Market Value of each share of Common Stock calculated in accordance with Section 2(j) of the Plan. The exercise price is subject to adjustment pursuant to Section 12 of the Plan. Vesting of Options. The Options shall be exercisable in installments in accordance with the following table, except as otherwise provided in the Plan: Date First Exercisable Number of Options DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) DATE ((NUMBER)) ----------- Total: ((NUMBER1)) Option Period. Each Option may be exercised at any time between the date at which it becomes exercisable and ten years from the Date of Grant, inclusive of such dates, except that in the event of the Optionee's death, or his or her Disability (defined under Section 2 of the Plan), or if there is a Change in Control of the Company, then the provisions of Sections 10(a), and 13 of the Plan, respectively, shall govern the option period. Method of Exercise. The Options are exercisable in accordance with the procedures, but subject to all conditions and restrictions, set forth in the Plan. 93 Transferability. The Options are not assignable or transferable except by will or the laws of descent and distribution. SWIFT ENERGY COMPANY By:_________________________________ The Optionee acknowledges receipt of a copy of the Plan, represents that he is familiar with the terms and provisions thereof, and hereby accepts the Options evidenced hereby subject to all the terms, provisions, conditions and restrictions of the Plan. -------------------------------------- Printed Name: ________________________ 94 SWIFT ENERGY COMPANY RESTRICTED STOCK AWARD AGREEMENT This RESTRICTED STOCK AWARD AGREEMENT (the "Agreement") is effective as of the ____ day of ______________, 200__, by and between SWIFT ENERGY COMPANY, a Texas corporation (the "Company") and ____________________, individually ("Participant"), in connection with the Participant's past and future employment with the Company. A. Award. The Company hereby grants to Participant a restricted stock award covering ________________ shares (the "Shares") of common stock, par value $.01 per share, of the Company according to the terms and conditions set forth herein and in the Company's 2001 Omnibus Stock Compensation Plan (the "Plan") and shall constitute a Restricted Stock Grant under Section 8 of the Plan. A copy of the Plan has been furnished or made available to the Participant. Participant hereby acknowledges (i) opportunity to review the Plan, (ii) Participant's understanding of the terms and provisions of the award and the Plan, and (iii) Participant's understanding that, by its signature below, Participant is agreeing to be bound by all of the terms and provisions of this award and the Plan. Without limitation, Participant agree to accept as binding, conclusive and final all decisions or interpretations (including, without limitation, all interpretations of the meaning of provisions of the Plan, or award, or both) of the Compensation Committee of the Company's Board of Directors upon any questions arising under the Plan, or this award, or both. B. Restrictions on Transfer. Until the award covering specified Shares vests pursuant to Section C below, the Shares may not be transferred, pledged, alienated, attached or otherwise encumbered, and any purported pledge, alienation, attachment or encumbrance shall be void and unenforceable against the Company, and no attempt to transfer the unvested portion of the award covering any of the Shares or the Shares, whether voluntary or involuntary, by operation of law or otherwise, shall vest the purported transferee with any interest or right in or with respect to such award or Shares. C. Vesting. Except as otherwise provided in this Agreement, the restrictions set out in Section B above shall lapse as to twenty percent (20%) of the Shares and the award covering such twenty percent (20%) of the Shares shall vest on February 8, 2006 (the "Vesting Date"), and twenty percent (20%) of the Shares shall vest on each anniversary of the Vesting Date thereafter until all of the Shares are fully vested unless earlier forfeited pursuant to the terms of Section D of this Agreement. D. Forfeiture. All of Participant's rights to all of the unvested portion of the award covering any of the Shares shall be immediately and irrevocably forfeited if Participant ceases to be an employee of the Company or any affiliate of the Company prior to vesting of all or any part of the Shares pursuant to Section C of this Agreement, whether or not employment is terminated with or without cause, unless the Compensation Committee shall determine otherwise. Upon forfeiture, Participant will no longer have any rights relating to unvested Shares, including the right to vote such Shares and the right to receive dividends, if any, declared on such Shares. E. Termination. This Agreement shall terminate (i) immediately without any notice upon termination of Participant's employment, with or without cause, or (ii) when all of the Shares are fully vested hereunder. F. Legends; Certificates. Participant agrees that each certificate representing unvested Shares will bear any legend required by law and a legend reading substantially as follows: 95 The securities represented by this certificate are subject to the provisions of a Restricted Stock Award Agreement with Swift Energy Company effective as of September 1, 2004. None of the securities represented by this certificate may be transferred, pledged, alienated, attached or otherwise encumbered, and any purported transfer, pledge, alienation, attachment or encumbrance shall be void and unenforceable against the Company, and no attempt to transfer, pledge, alienate, attach or encumber such securities, whether voluntary or involuntary, by operation of law or otherwise, shall vest the purported transferee, pledgee or the like with any interest or right in or with respect to such securities. Stock certificates shall be issued in respect of each twenty percent (20%) vesting block of the Shares in the name of Participant. Participant agrees that it shall deliver to the Company duly executed stock powers in blank for each certificate and that the Company shall hold all certificates representing unvested Shares accompanied by the executed stock power in escrow until such time such Shares represented by the certificate become vested. After vesting and upon delivery of written instructions by Participant, the Company shall remove the legend and re-issue a certificate to be delivered to Participant in accordance with Participant's written instructions. Miscellaneous. 1. Plan Provisions Control. In the event that any provision of the Agreement conflicts with or is inconsistent in any respect with the terms of the Plan, the terms of the Plan shall control. 2. No Right to Retention. The issuance of the Shares shall not be construed as giving Participant the right to be employed or continue to be employed by the Company or an affiliate of the Company, nor will it affect in any way the right of the Company or an affiliate of the Company to terminate such employment or position at any time, with or without cause, pursuant to the terms of an employment agreement, if any, or otherwise in accordance with applicable law. In addition, the Company or an affiliate of the Company may at any time terminate any employment agreement free from any liability or any claim under the Plan or this Agreement. Nothing in this Agreement shall confer on any person any legal or equitable right against the Company or any affiliate of the Company, directly or indirectly, or give rise to any cause of action at law or in equity against the Company or an affiliate of the Company. The award covering the Shares granted hereunder shall not form any part of the consideration, compensation of fees of Participant for purposes of termination indemnities, irrespective of the reason for termination of any employment agreement. Under no circumstances shall Participant be entitled to any compensation for any loss of any right or benefit under the Agreement or Plan which such Participant might otherwise have enjoyed but for termination of an employment agreement, whether such compensation is claimed by way of damages for breach of contract or otherwise. By entering into this Agreement, Participant shall participate in the Plan and be deemed to have accepted all the conditions of the Plan and the terms and conditions of any rules and regulations adopted by the Committee (as defined in the Plan) and shall be fully bound thereby. 3. Governing Law. The validity, construction and effect of the Plan and this Agreement, and any rules and regulations relating to the Plan and this Agreement, shall be determined in accordance with the internal laws, and not the law of conflicts, of the State of Texas. 4. Unenforceability. If any provision of this Agreement is or becomes or is deemed to be invalid, illegal or unenforceable in any jurisdiction or would disqualify the Agreement under any applicable law, such provision shall be construed or deemed amended to conform to applicable laws, or if it cannot be so construed or deemed amended without materially altering the purpose or intent of the Plan or the Agreement, such provision shall be stricken as to such jurisdiction or the Agreement, and the remainder of the Agreement shall remain in full force and effect. 5. No Trust or Fund Created. Neither the Plan nor the Agreement shall create or be construed to create a trust or separate fund of any kind or a fiduciary relationship between the Company or any affiliate of the Company and Participant or any other person. 96 6. Headings. Headings are given to the Sections and subsections of the Agreement solely as a convenience to facilitate reference. Such headings shall not be deemed in any way material or relevant to the construction or interpretation of the Agreement or any provision thereof. IN WITNESS WHEREOF, the Company and Participant have executed this Agreement effective as of the date set forth in the first paragraph. SWIFT ENERGY COMPANY By: ----------------------------- Name: --------------------------- PARTICIPANT -------------------------------- Print Name: --------------------- Title: -------------------------- 97 Exhibit 10.25 Description of Executive Officer Compensation Executive officer compensation is set by the Compensation Committee of Swift's Board of Directors on an annual basis, with base compensation set at the Committee's discretion without any specified weighting or formula, although individual performance and responsibility, along with compensation by peer companies and Swift's performance are typically factors evaluated by the Compensation Committee. Executive officer compensation is determined using the same system and methods applicable to compensation of all officers. Annual incentive bonuses for 2004 and prior periods have been paid in cash and also were determined by the Compensation Committee. Bonus awards for 2004 were based upon the Company reaching specified pre-determined growth targets in four areas, each with a one-sixth weighting: earnings per share, cash flow per share, volumes of proved oil and gas reserves and volumes of probable oil and gas reserves. The other factor with a one-third weighting was subjective, and measured an individual executive's personal performance based upon individual goals set at the beginning of the year. Other than the subjective analysis of individual performance, success was measured for all executive officers by the same factors. Success in these five areas was then measured against maximum target bonus ranges as percentages of base salaries. For 2005, the four objective factors have been expanded to additionally include: net margin per oil and gas equivalent produced, production growth, controllable lease operating expenses per oil and gas equivalent produced and finding costs per oil and gas equivalent reserves added, and the former two reserve growth categories have been combined to measure growth in proved and probable reserves taken together. The application of these seven factors has also been modified so that different factors and different percentages of base salary apply to different executive officers, with each executive officer given different weightings of these seven factors to measure performance. The one-third weighting based upon individual performance remains in place for 2005 and will continue to be monitored against individual goals determined at the beginning of the year. Long-term incentives, currently consisting of stock options and/or restricted stock, are awarded by the Compensation Committee historically toward the end of each year, although beginning in 2005 long-term incentives are anticipated to be awarded early in the following year, using different percentages of base salary for different level executive officers, with stock options valued using a Black-Scholes model, and restricted stock valued based upon prevailing market prices at the date of grant. Stock options to executive officers typically contain the same vesting provisions as stock options granted to all employees, with the exception of accelerated vesting provisions in specified circumstances for those executive and other officers with employment agreements. The only time restricted stock has been granted was in late 2004, with 20% to vest over 5 years, with the first 20% to vest February 8, 2006 and an additional 20% to vest on each February 7 thereafter until fully vested. It is currently anticipated that restricted stock awards will continue to be made in the future. 98 Exhibit 12 SWIFT ENERGY COMPANY RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31, ----------------------------------------------------------- 2002 2003 2004 GROSS G&A 26,074,408 29,803,405 37,850,281 NET G&A 10,564,849 14,097,066 17,787,125 INTEREST EXPENSE, NET 23,274,969 27,268,524 27,643,108 RENTAL & LEASE EXPENSE 1,923,451 2,173,313 2,375,598 INCOME BEFORE INCOME TAXES AND CUMULATIVE 18,408,289 50,739,178 101,440,242 EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE CAPITALIZED INTEREST 6,973,480 6,835,983 6,489,763 DEPLETED CAPITALIZED INTEREST 215,433 548,996 679,709 CALCULATED DATA EXPENSED OR NON-CAPITAL G&A (%) 40.52% 47.30% 46.99% NON-CAPITAL RENT EXPENSE 779,345 1,027,981 1,116,374 1/3 NON-CAPITAL RENT EXPENSE 259,782 342,660 372,125 FIXED CHARGES 30,508,231 34,447,167 34,504,996 EARNINGS 42,158,473 78,899,358 130,135,183 1.38 2.29 3.77
RATIO OF EARNINGS TO FIXED CHARGES (12/11) For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense, capitalized interest, amortization of debt issuance costs and discounts, and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes and cumulative effect of change in accounting principle before interest expense, net, depleted capitalized interest and that portion of rental expense deemed to be the equivalent of interest. 99 Exhibit 21 Swift Energy Company - Significant Subsidiaries Swift Energy International, Inc. Swift Energy New Zealand Limited Southern Petroleum (NZ) Exploration Limited 100 Exhibit 23 (a) CONSENT OF H.J. GRUY AND ASSOCIATES, INC. We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of references to H. J. Gruy and Associates, Inc. and to the inclusion of and references to our report, or information contained therin, dated January 27, 2005, prepared for Swift Energy Company in the Annual Report on Form 10-K of Swift Energy Company for the filing dated on or about March 15, 2005. H.J. GRUY AND ASSOCIATES, INC. by: ______________________________ Marilyn Wilson President & Chief Operating Officer Houston, Texas March 14, 2005 101 Exhibit 23 (b) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-112042, 333-67242, 333-45354, and 33-80228), pertaining to the Swift Energy Company 2001 Omnibus Stock Compensation Plan, Swift Energy Company 1990 Stock Compensation Plan (Amended and Restated as of May 13, 1997), Swift Energy Company 1990 Nonqualified Stock Option Plan (Amended and Restated as of May 13, 1997), Swift Energy Company Employee Savings Plan, Swift Energy Company Employee Stock Purchase Plan, and in the Registration Statements on Form S-3 (Nos. 333-112041 and 333-12831) of Swift Energy Company and in the related Prospectus and pertaining to the Swift Energy Company Employee Stock Ownership Plan of our reports dated March 11, 2005, with respect to the consolidated financial statements of Swift Energy Company, Swift Energy Company management's assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of Swift Energy Company, included in this Annual Report onForm 10-K for the year ended December 31, 2004. /s/ ERNST & YOUNG LLP Houston, Texas March 11, 2005 102 Exhibit 31.1 CERTIFICATION I, Terry E. Swift, certify that: 1. I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2004, of Swift Energy Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 15, 2005 /s/ Terry E. Swift -------------------------------------- Terry E. Swift Chief Executive Officer 103 Exhibit 31.2 CERTIFICATION I, Alton D. Heckaman, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K for the period ended December 31, 2004, of Swift Energy Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 15, 2005 /s/ Alton D. Heckaman, Jr. ----------------------------------- Alton D. Heckaman, Jr. Executive Vice President and Chief Financial Officer 104 Exhibit 32 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the accompanying Annual Report on Form 10-K for the period ended December 31, 2004 (the "Report") of Swift Energy Company ("Swift") as filed with the Securities and Exchange Commission on March 15, 2005, the undersigned, in his capacity as an officer of Swift, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Swift. Dated: March 15, 2005 /s/ Alton D. Heckaman, Jr. ----------------------------- Alton D. Heckaman, Jr. Executive Vice President and Chief Financial Officer Dated: March 15, 2005 /s/ Terry E. Swift ----------------------------- Terry E. Swift Chief Executive Officer 105 Exhibit 99.1 H.J. GRUY AND ASSOCIATES, INC. - -------------------------------------------------------------------------------- 333 Clay Street, Suite 3850, Houston, Texas 77002 o TEL. (713) 739-1000 o FAX (713) 739-6112 January 27, 2005 Swift Energy Company 16825 Northchase Drive, Suite 400 Houston, Texas 77060 Re: Year-End 2004 R Reserves Audit Gentlemen: At your request, we have independently audited the estimates of oil, natural gas, and natural gas liquid reserves and future net cash flows as of December 31, 2004, that Swift Energy Company (Swift) attributes to net interests owned by Swift. Based on our audit, we consider the Swift estimates of net reserves and net cash flows to be in reasonable agreement, in the aggregate, with those estimates that would result if we performed a completely independent evaluation effective December 31, 2004. The Swift estimated net reserves, future net cash flow, and discounted future net cash flow are summarized below: Domestic and International Proved Reserves - --------------------------------------------------------------------------------
Estimated Estimated Net Reserves Future Net Cash Flow -------------------------------- --------------------------------------------- Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year -------------------------------- --------------------------------------------- Proved Developed 42,037,852 193,310,761 $ 1,865,056,103 $ 1,181,747,770 Proved Undeveloped 38,229,356 124,935,533 $ 1,426,565,121 $ 839,126,752 ------------ ------------ -------------------- --------------------- Total Proved 80,267,208 318,246,294 $ 3,291,621,224 $ 2,020,874,522
106 Domestic Proved Reserves - --------------------------------------------------------------------------------
Estimated Estimated Net ReservesFuture Net Cash Flow --------------------------------- --------------------------------------------- Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year --------------------------------- -------------------- --------------------- Proved Developed 36,628,873 140,549,052 $ 1,686,081,612 $ 1,037,617,262 Proved Undeveloped 32,510,170 97,342,783 $ 1,267,049,676 $ 759,724,044 ----------- ----------- -------------------- --------------------- Total Proved 69,139,043 237,891,835 $ 2,953,131,288 $ 1,797,341,306 New Zealand Proved Reserves - -------------------------------------------------------------------------------- Estimated Estimated Net ReservesFuture Net Cash Flow Oil, NGL, & Discounted Condensate Gas at 10% (Barrels) (Mcf) Nondiscounted Per Year --------------------------------- -------------------- --------------------- Proved Developed 5,408,979 52,761,709 $ 178,974,491 $ 144,130,508 Proved Undeveloped 5,719,186 27,592,750 $ 159,515,445 $ 79,402,708 New Zealand Total 11,128,165 80,354,459 $ 338,489,936 $ 223,533,216
The discounted future net cash flows summarized in the above tables are computed using a discount rate of 10 percent per annum. Proved reserves are estimated in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). The definitions are included, in part, as Attachment I. The reserves discussed herein are estimates only and should not be construed as exact quantities. Future economic or operating conditions may affect recovery of estimated reserves and cash flows, and reserves of all categories may be subject to revision as more performance data become available. Swift represents that the future net cash flows discussed herein were computed using prices received for oil, natural gas, and natural gas liquids as of December 31, 2004. Domestic oil and condensate prices are based on a year-end 2004 reference price of $43.45 per barrel. Natural gas price is based on a year-end 2004 reference price of $6.18 per MMBtu. New Zealand oil and 107 condensate prices are based on a year-end 2004 reference price of $36.95 per barrel. The New Zealand gas prices are based on existing long-term contract prices. The sales price for natural gas liquids is based on a reference price of US$ 0.64 per gallon adjusted as necessary for existing contract terms. A differential is applied to the oil, condensate, natural gas, and natural gas liquids reference prices to adjust for transportation, geographic property location, and quality or energy content. Product prices, direct operating costs, and future capital expenditures are not escalated and therefore remain constant for the projected life of each property. Swift represents that the provided product sales prices and operating costs are in accordance with Securities and Exchange Commission guidelines. This audit has been conducted according to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information approved by the Board of Directors of the Society of Petroleum Engineers, Inc. Our audit included examination, on a test basis, of the evidence supporting the reserves discussed herein. We have reviewed the subject properties, and where we had material disagreements with the Swift reserve estimates, Swift revised its estimate to be in agreement. In conducting our audit, we investigated each property to the level of detail that we deem reasonably appropriate to form the judgements expressed herein. Based on our investigations, it is our judgement that Swift used appropriate engineering, geologic, and evaluation principles and methods that are consistent with practices generally accepted in the petroleum industry. Reserve estimates were based on extrapolation of established performance trends, material balance calculations, volumetric calculations, analogy with the performance of comparable wells, or a combination of these methods. Reserve estimates from volumetric calculations or from analogies may be less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserve was produced. Estimates of net cash flow and discounted net cash flow should not be interpreted to represent the fair market value for the audited reserves. The estimated reserves and cash flows discussed herein have not been adjusted for uncertainty. Future net cash flow as presented herein is defined as the future cash inflow attributable to the evaluated interest less, if applicable, future operating costs, ad valorem taxes, and future capital expenditures. Future cash inflow is defined as gross cash inflow less, if applicable, royalties and severance taxes. Future cash inflow and future net cash flow stated in this report exclude consideration of state or federal income tax. Future costs of facility and well abandonments and the restoration of producing properties to satisfy environmental standards are not deducted from cash flow. In conducting this audit, we relied on data supplied by Swift. The extent and character of ownership, oil and natural gas sales prices, operating costs, future capital expenditures, historical production, accounting, geological, and engineering data were accepted as represented, and we have assumed the authenticity of all documents submitted. No independent well tests, property inspections, or audits of operating expenses were conducted by our staff in conjunction with this work. We did not verify or determine the extent, character, status, or liability, if any, of production imbalances or any current or possible future detrimental environmental site conditions. 108 In order to audit the reserves and future cash flows estimated by Swift, we have relied in part on geological, engineering, and economic data furnished by our client. Although we instructed our client to provide all pertinent data, and we made a reasonable effort to analyze it carefully with methods accepted by the petroleum industry, there is no guarantee that the volumes of hydrocarbons or the cash flows projected will be realized. The reserve and cash flow projections discussed in this report may require revision as additional data become available. If investments or business decisions are to be made in reliance on these judgements by anyone other than our client, such person, with the approval of our client, is invited to visit our offices at his expense so that he can evaluate the assumptions made and the completeness and extent of the data available on which our opinions are based. This report is for general guidance only, and responsibility for subsequent decisions resides with the decision maker. Any distribution or publication of this work or any part thereof must include this letter in its entirety. Yours very truly, H.J. GRUY AND ASSOCIATES, INC. Texas Registration Number F-000637 by: /s/ Marilyn Wilson -------------------- Marilyn Wilson, P.E. President and Chief Operating Officer Attachment MW:pab F:\Admin\S\SWIFT\322\Revised 2004Audit\LHyear-endaudit2004.doc 109 -----END PRIVACY-ENHANCED MESSAGE-----