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FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2006Item 1 . Business See pages 25 and 26 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. Swift Energy was founded in 1979 and is headquartered in Houston, Texas. At year-end 2006, we had estimated proved reserves of 816.8 Bcfe with a PV-10 Value of $2.7 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). Our proved reserves at year-end 2006 were comprised of approximately 50% crude oil, 40% natural gas, and 10% NGLs; and 44% of our total proved reserves were proved developed. Our proved reserves are concentrated 64% in Louisiana, 22% in Texas, 13% in New Zealand, and 1% in other states. We currently focus primarily on development and exploration of fields in three domestic regions and in 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 645.8 Bcfe to 816.8 Bcfe over the five-year period ended December 31, 2006. Over the same period, our annual production has grown from 44.8 Bcfe to 70.2 Bcfe and our annual net cash provided by operations has increased from $139.9 million to $424.9 million. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities and acquisitions in our four core regions. More recently, we increased our production by 18% during 2006 as compared to our hurricane affected 2005 production. During 2006, our total proved reserves increased by 7%, primarily due to acquisitions of properties in our South Louisiana region. 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 both 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 and strategic opportunities. In general, we focus on drilling in our anchor assets and diversity properties in each of our four regions 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 also focus on 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, 2006, we replaced 159% of our production at an average cost of $2.76 per Mcfe. More recently, we replaced 178% of our 2006 production at an average cost of $4.29 per Mcfe. For 2007, we are targeting total production to increase 7% to 10% and proved reserves to increase 4% to 6% over 2006 levels. Our 2007 capital expenditures are currently budgeted at $350 million to $400 million, net of minor non-core dispositions and excluding any property acquisitions. Reserves Replacement Ratio and Reserves Replacement Cost Historically we have added proved reserves through both our drilling and acquisition activities. We believe that this strategy will continue to add reserves for us over the long-term; however, external factors beyond our control, such as adverse weather conditions, commodity market factors, and governmental regulations, could limit our ability to drill wells and acquire proved properties in the future. We calculate and analyze reserves replacement ratios and costs to use as benchmarks against certain of our competitors. These ratios and costs are limited in use by the inherent uncertainties in the reserves estimation process, and other factors discussed below. We have included below a listing of 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 reserves 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, commodity prices, new and existing government regulations, adverse weather conditions, competition within our industry, the requirement of new or upgraded infrastructure at the production site, and technological advances. The reserves replacement ratio is calculated using reserves replacement volumes divided by production volumes during a specific period. The reserves replacement volumes used in this calculation are listed in the “Supplemental Information (Unaudited)” section of this report, specifically in a table titled “Supplemental Reserves 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 reserves replacement volumes. Production volumes are also listed in the same table, and these production volumes are also used in the reserves replacement ratio calculation. The reserves replacement cost is calculated using reserves replacement volumes divided into 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 drilling 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 reserves 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. Concentrated Focus on Regions with Operational Control The concentration of our operations in four regions allows us to leverage our drilling unit and workforce synergies while minimizing the continued escalation of drilling and completion costs. Our average lease operating costs, excluding taxes, were $0.89, $0.79, and $0.71 per Mcfe in 2006, 2005, and 2004, respectively. Each of our four regions includes at least one anchor asset, previously termed a core area, and several diversity properties that are targeted for future growth. 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, in our South Louisiana region, we will apply the experience we have gained in Lake Washington to our Bay de Chene and Cote Blanche Island properties acquired at the end of 2004, which are also situated around salt domes. The value of this concentration is enhanced by our operational control of 94% of our proved oil and natural gas reserves base as of December 31, 2006. 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 advanced technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties as illustrated in our four regions. For instance, 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 18,700 BOE for the quarter ended December 31, 2006. We have also increased our proved reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 40.3 million BOE or 241.9 Bcfe, as of December 31, 2006. Additionally, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest in 1999 and since that time we have drilled 50 wells in New Zealand. 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 began our initial development activities of these properties in 2006. We intend to continue acquiring large acreage positions where we can grow production by applying advanced technologies and recovery methods using our experience and knowledge developed in our four regions. 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, 2006, our debt to capitalization was approximately 32%, while our debt to proved reserves ratio was $0.47 per Mcfe, and our debt to PV-10 ratio was 14%. 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 maintaining a strategic 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 periods covered as described in the “Commodity Risk” section of this report. Experienced Technical Team We employ 61 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 24 years of experience in their technical fields and have been employed by us for an average of over five years. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations. We increasingly use seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, pre-stack image enhancement reprocessing, amplitude versus offset datasets, coherency cubes, and detailed field reservoir depletion planning. In 2004, we completed our 3-D seismic survey covering our Lake Washington area. In 2006 we utilized this seismic data to drill all of our exploratory and development wells. In 2005, we began a seismic program that encompasses 77 square miles in our Cote Blanche Island area, which was completed in 2006 and analysis of this data will continue into 2007. We now have seismic data covering 4,000 square miles in South Louisiana that has been merged into two data sets, inclusive of data covering five newly acquired fields that will form the base dataset for our regional exploration and development program. This data will be analyzed over the next several years feeding our acquisition and organic growth led strategies. In New Zealand, we also acquired seismic on our offshore Kaheru exploration permit in 2006. 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. We also employ measurement-while-drilling techniques extensively in our South Louisiana region, which allows us to guide the drill bit during the drilling process. This technology allows the well bore path to be steered parallel to the salt face and to intersect multiple targeted sands in a single well bore. |
Item 2. Properties
Operating Areas
The following table sets forth information regarding our 2006 year-end proved reserves of 816.8 Bcfe and production of 70.2 Bcfe by field:
| % of Year-End | |||||
| 2006 Proved | % of 2006 | ||||
|
Area |
Reserves | Production | |||
| --------------------- | ----------------- | ----------- | |||
| New Zealand | 13% | 19% | |||
| South Louisiana | 53% | 61% | |||
| South Texas | 18% | 12% | |||
| Toledo Bend | 14% | 6% | |||
| ----------------- | ------------- | ||||
| % of Total | 98% | 98% | |||
| ----------------- | ------------- |
Domestic Regional Focus Areas
Our domestic regions consist of three main regions located in South Louisiana, South Texas and Toledo Bend, which straddles the Texas and Louisiana border. South Texas is the oldest of our core regions, with our operations being established in the AWP Olmos area in 1989. In mid-1998, we acquired the Masters Creek and Brookeland areas in the Toledo Bend region, with South Bearhead Creek being our most recent acquisition in this region during late 2005. In South Louisiana, we established our operations when we acquired majority interests in producing properties in the Lake Washington field in early 2001, adding Bay de Chene and Cote Blanche Island in December 2004, and adding five fields in 2006: Bayou Sale, Bayou Penchant, High Island, Horseshoe Bayou, and Jeanerette.
South Louisiana
Lake Washington Area. As of December 31, 2006, we owned drilling and production rights in 21,690 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana. Approximately 93% of our proved reserves of 40.3 million BOE in this area at December 31, 2006, were oil and NGLs. To date, we have primarily produced from multiple Miocene sands ranging in depth from greater than 2,000 feet to 13,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its discovery in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 146 producing wells is gathered to three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with rigs on barges.
In 2006, we drilled 21 development wells, of which 18 wells were completed. At year-end 2006, we had 109 proved undeveloped locations in this field. Our planned 2007 capital expenditures in this area will focus on drilling from 24 to 26 wells, along with the construction of a facility on the west side of the field to further improve the deliverability and efficiency in this area.
Bay de Chene and Cote Blanche Island Areas. Bay de Chene is located in Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in St. Mary Parish, both of which are in South Louisiana in close proximity to Lake Washington. These fields hold predominantly undeveloped reserves. As of December 31, 2006, we owned drilling and production rights in 16,138 net acres in the Bay de Chene field and 7,030 net acres in the Cote Blanche Island field, along with options covering another 16,650 acres in the Cote Blanche Island field. At year-end 2006, we had five proved undeveloped locations in the Bay de Chene field and 26 in the Cote Blanche Island field. We drilled six development wells in Bay de Chene in 2006, of which three were completed, and we drilled three successful development wells in Cote Blanche Island. During 2007, we plan to drill six to eight wells in Bay de Chene and up to two wells in Cote Blanche Island, along with processing the 3-D seismic data that was shot in Cote Blanche Island in 2006.
Newly Acquired South Louisiana Areas. In October 2006, we acquired interests in five fields located in five primarily onshore South Louisiana fields: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), High Island Field in Cameron Parish and Bayou Penchant Field in Terrebonne Parish. Bayou Sale and Horseshoe Bayou fields are adjacent to each other and located 13 miles southeast of our Cote Blanche Island field. Production in these fields is from formations at depths ranging from 10,000 to 14,000 feet. The Bayou Penchant field was discovered in the 1930s and produces from a number of Middle Miocene sands at depths of 7,000 to 10,000 feet. Bayou Penchant is located approximately 44 miles southeast of Cote Blanche Island and is a non-operated field with Swift holding a 50% working interest. The High Island field is located 65 miles west of Cote Blanche Island and was discovered in 1983. The Jeanerette field is positioned on the flank of a large salt dome and approximately 12 miles north of Cote Blanche Island. Jeanerette Field produces from the Planulina sands in the 10,000 feet to 15,000 feet depth range. We plan to initiate an exploration and development program in 2007 to drill proved undeveloped and probable locations, recomplete several wells, enhance facilities and improve per unit operating costs in these five fields.
South Texas
AWP Olmos Area. As of December 31, 2006, we owned drilling and production rights in 29,278 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 70% natural gas. At year-end 2006, we owned interests in and operated 540 wells in this area producing oil and 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 these operated wells.
In 2006, we completed 14 development wells in this area, performed 26 fracture enhancements, but were unsuccessful on five very shallow exploration wells which cost $0.5 million in the aggregate. At year-end 2006, we had 110 proved undeveloped locations. Our planned 2007 capital expenditures will focus on drilling 10 to 12 wells in this area.
Toledo Bend
Brookeland Area. As of December 31, 2006, we owned drilling and production rights in 79,593 net acres and 3,500 fee mineral acres in the Brookeland area. This area is 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 in this area. The reserves are approximately 57% oil and natural gas liquids. During 2006, we drilled one development well, which was successful. At year-end 2006, we had ten proved undeveloped locations. Our planned 2007 capital expenditures in the Brookeland area include drilling one to two development wells.
Masters Creek Area. As of December 31, 2006, we owned drilling and production rights in 41,988 net acres and 91,594 fee mineral acres in the Masters Creek area. 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 69% oil and NGLs. At year-end 2006, we had nine proved undeveloped locations. We do not plan on drilling any wells in this area in 2007.
South Bearhead Creek Area. In November and December 2005, and then in December 2006, we acquired interests in the South Bearhead Creek field, which is located in the Toledo Bend region approximately 50 miles south of our Masters Creek field and 30 miles north of Lake Charles, Louisiana. Oil and gas are produced in this area predominantly from the upper and lower Wilcox sands at depths ranging from approximately 10,600 to 14,100 feet. The field also has production in the Cockfield sands at approximately 8,000 to 8,500 feet. South Bearhead Creek field was discovered in 1958 by a major oil company. It is a large east-west trending anticlinal closure and has had cumulative production of over 4 million BOE.
In 2006, we drilled three development wells in the area, all of which were successful. As of December 31, 2006, we owned drilling and production rights in 6,258 net acres in the South Bearhead Creek area. At year-end 2006, we had 19 proved undeveloped locations in this field. Our 2007 plans for this area include two to four development wells and several recompletions.
Dispositions. In April 2006, we sold our minority interest in the natural gas processing plant and related infrastructure that serves the Brookeland and the Masters Creek areas within our Toledo Bend region. In December 2006, we sold our interest in wells in the Garcia Ranch area within the South Texas region.
New Zealand Regional Focus Area
Our New Zealand region contains two anchor assets, the Rimu/Kauri area and the TAWN area. Our activity in New Zealand began in 1995. As of December 31, 2006, our exploration and production permits, all of which we operate, total 314,360 acres (182,381 net acres). Our 2007 planned activity in New Zealand includes conducting a major 3-D seismic survey and possibly drilling two development wells. Our infrastructure in New Zealand 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.
Rimu/Kauri Area. Since 2002, we have held a 100% working interest in petroleum mining permit 38151 covering approximately 4,552 acres in the Rimu area for a primary term of 30 years. We were awarded a 30-year primary term mining permit (PMP 38155) covering approximately 8,708 acres in the Kauri area in April 2005. During 2006, we completed two out of three development wells in the Kauri area and were unsuccessful with one exploratory well. One of the development wells successfully targeted the Kauri and Tariki sands, and the other was completed in the Manutahi sand. 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.
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 is Contact Energy. In 2006, we completed the Waihapa H-1 development well in the Tikorangi sand in this area and were unsuccessful with two exploratory wells, the Trapper and Goss. The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area.
Diversity Areas. A 152 square kilometer (59 square miles) marine 3-D seismic survey was recorded in production exploration permit 38495 over the Kaheru prospect, which is situated on the southern, offshore extension of the productive Rimu-Kauri structural trend, as a precursor to the possible drilling of an exploratory well on this prospect in 2008. We own 50% of this prospect.
In December 2004, we entered into a farm-in agreement with Ballance Agri-Nutrients Limited of New Zealand for 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 now have an 80% working interest. The Kowhai A-1 exploratory well was drilled in this area in the second half of 2006 but was unsuccessful.
Summary of New Zealand Government Licenses and Permits
Our acreage in New Zealand is licensed from the New Zealand government under production exploration permits (PEP), production mining licenses (PML), and production mining permits (PMP). These licenses and permits as of December 31, 2006 are summarized in the following table:
|
Date of |
||
|
Initial Interest |
Swift’s |
|
|
Permit |
Acquired |
Interest |
| PEP 38495 | 2005 | 50% |
|
PEP 38742 |
2004 |
80% |
|
PML 38138 |
2002 |
100% |
|
PML 38139 |
2002 |
100% |
|
PML 38140 |
2002 |
100% |
|
PML 38141 |
2002 |
100% |
|
PMP 38151 |
2002 |
100% |
| PMP 38155 | 2005 | 100% |
Details of these licenses can be found on the New Zealand government’s Crown Minerals website 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, 2006, 2005, and 2004. 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 were provided by us.
Estimates of future net revenues from our proved reserves and their 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 reserves 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. 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. Our hedges at year-end 2006 consisted of natural gas price floors with strike prices higher than the period-end price but did not materially affect prices used in these calculations. The weighted averages of such year-end 2006 prices domestically were $5.84 per Mcf of natural gas, $60.07 per barrel of oil, and $31.54 per barrel of NGL, compared to $10.36, $60.00, and $33.28 at year-end 2005 and $5.87, $42.21, and $26.49 at year-end 2004, respectively. The weighted averages of such year-end 2006 prices for New Zealand were $3.59 per Mcf of natural gas, $63.51 per barrel of oil, and $26.84 per barrel of NGL, compared to $3.79, $60.98, and $19.20 in 2005 and $3.07, $33.60, and $20.48 in 2004, respectively. The weighted averages of such year-end 2006 prices for all our reserves, both domestically and in New Zealand, were $5.46 per Mcf of natural gas, $60.41 per barrel of oil, and $30.93 per barrel of NGL, compared to $8.94, $60.12, and $31.40 in 2005 and $5.16, $41.07, and $25.48 in 2004, respectively.
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 Securities and Exchange Commission and their PV-10 Value as of December 31, 2006, 2005, and 2004. 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, which is calculated after provision for future income taxes. We combine NGLs with oil for reserves reporting purposes. PV-10 is a non-GAAP measure; see the reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure, in the section below this table.
As of December 31, 2006 Total Domestic New Zealand Estimated Proved Oil and Natural Gas Reserves Natural gas reserves (MMcf): Proved developed 151,276 133,815 17,462 Proved undeveloped 172,855 135,846 37,009 ------------ ------------ ------------ Total 324,131 269,661 54,471 Oil reserves (MBbl): ======= ======= ======= Proved developed 34,956 33,346 1,611 Proved undeveloped 47,163 40,119 7,044 ------------ ------------ ------------ Total 82,119 73,465 8,655 ======= ======= ======= Total Estimated Reserves (Bcfe) 817 710 107 Estimated Discounted Present Value of Proved Reserves (In millions) Proved developed $1,382 $1,307 $75 Proved undeveloped 1,326 1,137 189 ------------ ------------ ------------ PV-10 Value $ 2,708 $ 2,444 $ 264 ======= ======= =======
| As of December 31, 2005 | |||
| Total | Domestic | New Zealand | |
| Estimated Proved Oil and Natural Gas Reserves | |||
| Natural gas reserves (MMcf): | |||
| Proved developed | 152,001 | 125,368 | 26,633 |
| Proved undeveloped | 135,472 | 99,907 | 35,565 |
| ------------ | ------------ | ------------ | |
| Total | 287,473 | 225,275 | 62,198 |
| ======= | ======= | ======= | |
| Oil reserves (MBbl): | |||
| Proved developed | 37,990 | 35,298 | 2,691 |
| Proved undeveloped | 41,063 | 34,485 | 6,579 |
| ------------ | ------------ | ------------ | |
| Total | 79,053 | 69,783 | 9,270 |
| ======= | ======= | ======= | |
| Total Estimated Reserves (Bcfe) | 762 | 644 | 118 |
| Estimated Discounted Present Value of Proved Reserves (In millions) | |||
| Proved developed | $ 1,721 | $ 1,612 | $ 109 |
| Proved undeveloped | 1,450 | 1,248 | 202 |
| ------------ | ------------ | ------------ | |
| PV-10 Value | $ 3,171 | $ 2,860 | $ 311 |
| ======= | ======= | ======= | |
| 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 |
| ======= | ======= | ======= | |
| Total Estimated Reserves (Bcfe) | 800 | 653 | 147 |
| Estimated Discounted Present Value of Proved Reserves (In millions) | |||
| Proved developed | $ 1,182 | $ 1,038 | $ 144 |
| Proved undeveloped | 839 | 760 | 79 |
| ------------ | ------------ | ------------ | |
| PV-10 Value | $ 2,021 | $ 1,797 | $ 224 |
| ======= | ======= | ======= | |
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.
No other reports on our reserves have been required to be filed, nor have any been filed with any federal agency.
The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized measure of discounted future net cash flows. We believe PV-10 is a helpful measure in evaluating the value of our oil and gas reserves and many securities analysts and investors use PV-10. We use PV-10 in our ceiling test computations, and we also compare PV-10 against our debt balances. The following table is a reconciliation between PV-10 and the standardized measure of discounted future net cash flows:
|
|
As of December 31, 2006 | ||
| Total | Domestic | New Zealand | |
| (In millions) | |||
| PV-10 Value | $ 2,708 | $ 2,444 | $ 264 |
| ======= | ======= | ======= | |
| Future income taxes (discounted at 10%) | (800) | (778) | (22) |
| Asset retirement obligations (discounted at 10%) | (39) | (34) | (5) |
| -------------- | -------------- | -------------- | |
| Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves | $ 1,869 | $ 1,632 | $ 237 |
| ======= | ======= | ======= | |
|
|
As of December 31, 2005 | ||
| Total | Domestic | New Zealand | |
| (In millions) | |||
| PV-10 Value | $ 3,171 | $ 2,860 | $ 311 |
| ======= | ======= | ======= | |
| Future income taxes (discounted at 10%) | (984) | (942) | (42) |
| Asset retirement obligations (discounted at 10%) | (27) | (23) | (4) |
| -------------- | -------------- | -------------- | |
| Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves | $ 2,159 | $ 1,895 | $ 265 |
| ======= | ======= | ======= | |
| As of December 31, 2004 | |||
| Total | Domestic | New Zealand | |
| (In millions) | |||
| PV-10 Value | $ 2,021 | $ 1,797 | $ 224 |
| ======= | ======= | ======= | |
| Future income taxes (discounted at 10%) | (533) | (521) | (12) |
| Asset retirement obligations (discounted at 10%) | (23) | (19) | (4) |
| -------------- | -------------- | -------------- | |
| Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves | $ 1,465 | $ 1,257 | $ 208 |
| ======= | ======= | ======= | |
Proved Undeveloped Reserves
The following table sets forth the aging and PV-10 value of our proved undeveloped reserves as of December 31, 2006:
|
Year Added |
Volume (Bcfe) |
% of PUD Volumes |
PV-10 Value (in millions) |
% of PUD |
|||
| 2006 | 111.9 | 25% | 315.9 | 24% | |||
| 2005 | 110.6 |
24% |
406.5 | 31% | |||
| 2004 | 58.4 |
13% |
189.9 | 14% | |||
| 2003 | 51.4 |
11% |
171.4 | 13% | |||
| 2002 | 40.3 |
9% |
91.6 | 7% | |||
| Prior to 2002 | 83.2 | 18% | 151.2 | 11% | |||
| ------------ | ------------ | ------------ | ------------ | ||||
| Total | 455.8 |
100% |
$ 1,326.5 | 100% | |||
| ======== | ======== | ======== | ======== |
Sensitivity of Reserves to Pricing
As of December 31, 2006, a 5% increase in crude oil and NGL pricing would increase our total estimated proved reserves of 816.8 Bcfe by approximately 0.6 Bcfe, and increase the total PV-10 Value of $2.7 billion by approximately $139 million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.6 Bcfe and decrease the total PV-10 Value by approximately $138 million.
As of December 31, 2006 a 5% increase in natural gas pricing (exclusive of fixed contract volumes) would increase our total estimated proved reserves by approximately 0.7 Bcfe and increase the total PV-10 Value by approximately $42 million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed contract volumes) would decrease our total estimated proved reserves by approximately 0.6 Bcfe and decrease the total PV-10 Value by approximately $42 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 Wells1 | |
| --------------- | --------------- | --------------- | |
| December 31, 2006 | |||
| Gross | 423 | 662 | 1,085 |
| Net | 353.4 | 562.4 | 915.8 |
| December 31, 2005 | |||
| Gross | 402 | 565 | 967 |
| Net | 324.8 | 497.5 | 822.3 |
| December 31, 2004 | |||
| Gross | 358 | 574 | 932 |
| Net | 308.8 | 525.9 | 834.7 |
(1) Excludes 51 service wells in 2006, 49 service wells in 2005, and 40 service wells in 2004.
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2006:
| Developed(1) | Undeveloped(1) | |||
| Gross | Net | Gross | Net | |
| Alabama | 9,045 | 2,588 | 124 | 80 |
| Alaska | --- | --- | 45,301 | 15,994 |
| Louisiana | 126,472 | 106,133 | 48,376 | 43,464 |
| Texas | 129,997 | 90,165 | 18,271 | 13,239 |
| Wyoming | 640 | 151 | 35,771 | 33,975 |
| All other states | 320 | 266 | 400 | 258 |
| Offshore Louisiana | 4,609 | 277 | 5,000 | 258 |
| ---------------- | ---------------- | ---------------- | ---------------- | |
| Total Domestic | 271,083 | 199,580 | 153,243 | 107,268 |
| New Zealand | 9,960 | 9,912 | 304,400 | 172,469 |
| ---------------- | ---------------- | ---------------- | ---------------- | |
| Total | 281,043 | 209,492 | 457,643 | 279,737 |
| ========== | ========== | ========== | ========== | |
(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 68,689 undeveloped fee mineral acres for a total of 95,034 fee mineral acres.
Drilling Activities
The following table sets forth the results of our drilling activities during the three years ended December 31, 2006:
| Gross Wells | Net Wells | |||||||||||
| Year | Type of Well | Total | Producing | Dry | Total | Producing | Dry | |||||
| 2006 | Exploratory--Domestic | 6 | -- | 6 | 5.5 | -- | 5.5 | |||||
| Development--Domestic | 49 | 42 | 7 | 47.6 | 40.6 | 7.0 | ||||||
| Exploratory--New Zealand | 4 | -- | 4 | 4.0 | -- | 4.0 | ||||||
| Development--New Zealand | 4 | 3 | 1 | 4.0 | 3.0 | 1.0 | ||||||
|
|
||||||||||||
| 2005 | Exploratory--Domestic | 9 | 5 | 4 | 9.0 | 5.0 | 4.0 | |||||
| Development--Domestic | 45 | 37 | 8 | 44.3 | 36.3 | 8.0 | ||||||
| Exploratory--New Zealand | 5 | 1 | 4 | 3.7 | 1.0 | 2.7 | ||||||
| Development--New Zealand | 5 | 2 | 3 | 5.0 | 2.0 | 3.0 | ||||||
|
|
||||||||||||
| 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 Zealand | 1 | --- | 1 | 1.0 | --- | 1.0 | ||||||
| Development--New Zealand | 11 | 10 | 1 | 11.0 | 10.0 | 1.0 | ||||||
Operations
We generally seek to be the operator of 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 this 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 2006 totaled $8.8 million and ranged from $529 to $2,345 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 usually 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. In 2005 and 2006, several companies accounted for 10% or more of our total revenues. Shell Oil Company and its affiliates, both domestically and in New Zealand, accounted for approximately 30% and 42% of our total oil and gas sales in 2006 and 2005, respectively. In 2006, Chevron and its domestic affiliates accounted for 32% of our total oil and gas sales. However, due to the demand for oil and gas and 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.
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.
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 terminated earlier. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future.
In the Toledo Bend area, our oil production from the Brookeland, Masters Creek and South Bearhead Creek areas is sold to various purchasers at prevailing market prices. Our natural gas production from the Brookeland and Masters Creek areas is processed under long term gas processing contracts with Eagle Rock Operating, LLC. The processed liquids and residue gas production are sold in the spot market at prevailing prices. South Bearhead Creek gas production is sold into the interstate market on Trunkline Gas Company’s pipeline at prevailing market prices.
Our oil production from the Bay de Chene and Cote Blanche Island fields is transported on barges for sales to various purchasers at prevailing market prices. Gas production from both fields is sold into intrastate pipelines with prices tied to monthly and daily gas price indices.
In the newly acquired fields of Bayou Sale, Horseshoe Bayou, High Island and Jeanerette in south Louisiana, we market our own production and sell the oil production to various purchasers at prevailing market prices. Bayou Sale and Horseshoe Bayou oil production is delivered into Plains All-American pipeline. Oil production from High Island and Jeanerette fields is transported to market by truck. Gas production for each of these fields is sold into one or more interstate pipelines at prevailing market prices.
Through 2006, our oil production in New Zealand was sold to BP with prices tied to the Asia Petroleum Price Index (APPI) Tapis posting.
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 2006 and covers approximately 7.2 Bcfe per year for a three-year period. During 2006, 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.
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, 2006:
|
Year Ended December 31, |
|||
|
2006 |
2005 |
2004 |
|
| Net Sales Volume: | |||
| Oil (MBbls)(1) | 7,190 | 5,159 | 4,722 |
| Natural Gas Liquids (MBbls)(2) | 713 | 838 | |