Swift Energy Company 10-K 2011
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2010
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
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.
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. [þ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold on the New York Stock Exchange as of June 30, 2010, the last business day of June 2010, was approximately $1,019,313,879.
The number of shares of common stock outstanding as of January 31, 2011 was 42,049,082.
Documents Incorporated by Reference
Swift Energy Company and Subsidiaries
Items 1 and 2. Business and Properties
See pages 25 and 26 for explanations of abbreviations and terms used herein.
Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and natural gas properties, with a focus on oil and natural gas reserves in Texas as well as onshore and in the inland waters of Louisiana. Swift Energy was founded in 1979 and is headquartered in Houston, Texas. At year-end 2010, we had estimated proved reserves from our continuing operations of 132.8 MMBoe with a PV-10 of $1.8 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 total proved reserves at year-end 2010 were approximately 30% crude oil, 53% natural gas, and 17% NGLs; and 45% of our total proved reserves were proved developed. Our proved reserves are concentrated with 40% in Louisiana and 59% in Texas.
We currently focus primarily on development and exploration of four core areas. The major fields in our core areas are:
• South Texas
Hawkville Artesia Wells
• Southeast Louisiana
Bay de Chene
• Central Louisiana/East Texas
South Bearhead Creek
• South Louisiana
Horseshoe Bayou/Bayou Sale
Cote Blanche Island
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 strengths and strategies are set forth below.
Demonstrated Ability to Grow Reserves and Production
We have grown our proved reserves from 107.3 MMBoe to 132.8 MMBoe over the five-year period ended December 31, 2010. Over the same period, our annual production has grown from 7.2 MMBoe to 8.3 MMBoe. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities and acquisitions in our core areas. During 2010, our proved reserves increased by 18%, due mainly to additional drilling in our South Texas core area. Based on our long-term historical performance and our business strategy going forward, we believe that we have the opportunities, experience, and knowledge to continue growing 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 use acquisitions to gain entry into new core areas and then increase reserves and production through development and exploratory activities within these areas. Through our strategic growth initiatives we target locations outside of our core areas for new exploration opportunities. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner. We have replaced 154% of our production on average over the last five years.
We currently plan to balance our 2011 capital expenditures with our 2011 cash flow, cash on hand and potential line of credit borrowings. Our 2011 capital expenditures are currently budgeted at $430 million to $480 million, net of potential dispositions of non-strategic properties. Approximately 80% of our capital budget is targeted for our South Texas core area. The Company may also explore both joint venture arrangements for particular prospects and select property dispositions, in each case to accelerate drilling and development of its assets and diversify its risk profile. For 2011, are targeting an increase in production volumes of 25% to 30% over 2010 levels and reserves growth of 15% to 20% over 2010 levels.
Replacement of Reserves
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 limited availability of capital or its cost, competition within our industry, adverse weather conditions, commodity market factors, the requirement of new or upgraded infrastructure at the production site, technological advances, and governmental regulations, could limit our ability to drill wells, access reserves, and acquire proved properties in the future. We have included 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 natural gas production. Our reserves additions for each year are estimates. Reserves 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.
Concentrated Focus on Core Areas with Operational Control
The concentration of our operations in our core areas 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 for continuing operations, excluding taxes, were $9.84, $8.47 and $10.44 per Boe in 2010, 2009, and 2008, respectively. Each of our core areas includes 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 types of assets. The value of this concentration is enhanced by our operational control of 93% of our proved oil and natural gas reserves base as of December 31, 2010. 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 core areas. For instance, in 1989 we acquired producing properties in the AWP field in McMullen County, TX from a major producer. This field had been developed in the early 1980’s and was considered close to maturity when we made this acquisition. The Company began to acquire adjacent undeveloped acreage and in 1994 launched an aggressive drilling program. This area has remained a cornerstone of our operations as we have pursued other opportunities. Since assuming operations in this area, our drilling and completion techniques have been continuously refined to improve hydrocarbon recovery from the tight sand Olmos formation. Almost all of our existing interest overlays portions of the now very active Eagle Ford shale play which is being developed through the combination of horizontal drilling and multi-stage fracture stimulation completion techniques. While the combination of proven drilling and completion technologies have allowed us to begin to exploit the Eagle Ford shale, we have applied the same methods to further develop the “mature” Olmos sand. As a result we substantially increased our Olmos production and reserves during 2010 even though we have been producing from this formation for over 20 years. The Company has acquired 750 square miles of 3D seismic data over the AWP Field. We began merging and prestack time migrating this data into a continuous data set that we are using to plan our wells and enhance and expand our developments. Another of our significant successes is the Lake Washington field. This 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 a peak of over 18,000 Boe. We have utilized enhanced 3-D seismic and various completion techniques including sliding sleeves to improve drilling success and production performance. When we acquired this field we booked 7.7 MMBoe of reserves. Since acquisition we produced 45 MMBoe and still have remaining proved reserves of 17.7 MMBoe. In October 2007, we acquired interests in two South Texas properties in the Gulf Coast basin (Sun TSH and Las Tiendas) which, along with AWP, have acreage prospective for Eagle Ford shale development. These properties are located in the Sun TSH field in La Salle County and the Las Tiendas field in Webb County. 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 core areas.
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, 2010, our debt to capitalization was approximately 35%, while our debt to proved reserves ratio was $3.55 per Boe, and our debt to PV-10 ratio was 25%. 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 when appropriate.
Experienced Technical Team and Technology Utilization
We employ 64 oil and gas technical 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 approximately six 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 advanced technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, licensing and pre-stack time and depth imaging, advanced attributes, pore-pressure analysis, inversion and detailed field reservoir depletion planning. In 2004, we recorded a 3-D seismic survey covering our Lake Washington field, and in 2006 we recorded a second 3-D survey in and around our Cote Blanche Island field. We now have proprietary pre-stack time and depth migrated seismic data covering over 4,000 square miles in South Louisiana. These data have been merged into two large data volumes, inclusive of data covering five fields we acquired in 2006. In late 2007, we began to extend this methodology to South Texas and have subsequently licensed over 750 square miles of 3-D seismic data. In late 2010, we initiated a project to reprocess, calibrate, merge and prestack time-migrate 700 square miles of 3-D seismic data over and near our AWP field. As these data are processed and merged with other available seismic data, and integrated with geologic data, we develop proprietary geo-science databases that we use to guide our exploration and development programs.
We use various recovery techniques, including gas lift, water flooding, pressure maintenance, and acid treatments to enhance crude oil and natural gas production. We also fracture reservoir rock through the injection of high-pressure fluid, the installation of gravel packs, and the insertion of coiled-tubing velocity strings to enhance and maintain production. 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 South Texas Olmos and Eagle Ford operations. By December 31, 2010, we had successfully drilled and completed 30 horizontal multistage fracture completions in our South Texas area. We will continue to improve and employ this new technology in South Texas and apply this to other areas in which Swift Energy operates.
Swift Energy’s success at drilling both in South Texas and in Louisiana can be marked by requiring excellence in engineering. This is accomplished by elevating the quality of engineering first and operations second, with a focus on continuing improvement. A premium is placed on well planning. Drilling guidelines and design specifications are developed and implemented as best practices and standards, respectively, from which all planning and execution is derived. The emphasis on well planning has permeated throughout the organization and the results of that planning constantly show up in performance across all drilling operations. Lastly, the quality of the equipment and field personnel, together with a complete drilling process, is consistently enforced. This is the final mixture of resources that aids Swift Energy in moving toward becoming a top tier company.
Operating Areas (Continuing Operations)
The following table sets forth information regarding our 2010 year-end proved reserves from continuing operations of 132.8 MMBoe and production of 8.3 MMBoe by area:
Our operations are primarily focused in four core areas identified as Southeast Louisiana, South Texas, Central Louisiana/East Texas, and South Louisiana. In addition, we have a strategic growth area with acreage in the Four Corners area of southwest Colorado. South Texas is the oldest of our core areas, with our operations first established in the AWP field in 1989 and subsequently expanded with the acquisition of the Sun TSH and Las Tiendas fields during 2007. Operations in our Central Louisiana/East Texas area began in mid-1998 when we acquired the Masters Creek field in Louisiana and the Brookeland field in Texas, later adding the South Bearhead Creek field in Louisiana in late 2005. The Southeast Louisiana and South Louisiana areas were established when we acquired majority interests in producing properties in the Lake Washington field in early 2001, in the Bay de Chene and Cote Blanche Island fields in December 2004, and in the Bayou Sale, Bayou Penchant, Horseshoe Bayou, and Jeanerette fields in 2006.
Eagle Ford. In 2010 the Company initiated an active exploration and development program in the Eagle Ford formation. During the year the Company drilled 22 wells in the Eagle Ford, including six non-operated joint venture wells. We completed 14 of the operated and three of the non-operated wells during the year. Four of the five wells awaiting completion at year-end have subsequently been completed. The Company owns a 50% working interest in the joint venture wells. These wells are operated by our partner during the drilling and completion phase. Swift Energy assumes operations when the wells are placed on production.
As of December 31, 2010, we owned drilling and production rights to 78,911 net acres overlaying the Eagle Ford, of which 73,764 are undeveloped. Based on the results of wells drilled in 2010 we have identified 56 proved undeveloped locations. During 2011 we plan to drill 25 wells targeting the Eagle Ford, including six wells to be drilled through our joint venture. Our December 31, 2010 proved reserves in this formation are 75% natural gas, 19% oil, and 6% natural gas liquids on a Boe basis.
Olmos. In the Olmos formation, from which the Company has been producing since 1989, we drilled 10 horizontal wells and six vertical Olmos wells in 2010. These wells were all operated and 100% owned by Swift Energy. We completed eight of the horizontal wells during 2010 and one was completed shortly after year-end. One of the horizontal wells had a mechanical failure and was not completed. We completed five of six vertical wells during the year and one was abandoned. We also performed 16 fracture enhancements during the year. As of December 31, 2010 we owned drilling and production rights in 109,339 net acres overlying the Olmos (much of which also overlaps the Eagle Ford) in South Texas, of which 65,466 is undeveloped. At year-end we were operating 849 wells producing oil and natural gas from the Olmos sand formation at depths from 9,000 to 11,500 feet. Our South Texas reserves in this formation are approximately 61% natural gas, 32% natural gas liquids, and 7% oil on a Boe basis. At year-end 2010, we had 87 proved undeveloped locations in the Olmos. Our planned 2011 capital expenditures will include drilling up to 14 horizontal wells targeting the Olmos formation, and we plan to perform approximately 35 production enhancement projects including fracture stimulations, pumping unit installations and installation of additional compression.
Lake Washington. As of December 31, 2010, we owned drilling and production rights in 16,161 net acres in the Lake Washington field located in Southeast Louisiana nearshore waters within Plaquemines Parish. Since its discovery in the 1930’s, the field has produced over 300 million Boe from multiple stacked Miocene sand layers radiating outward from a central salt dome and ranging in depth from 2,000 feet to 13,000 feet. The area around the dome is heavily faulted, thereby creating a large number of potential hydrocarbon traps. Approximately 93% of our proved reserves of 17.7 MMBoe in this field as of December 31, 2010, consisted of oil and NGLs. Oil and natural gas from approximately 103 currently producing wells is gathered to several platforms located in water depths from 2 to 12 feet, with drilling and workover operations performed with rigs on barges.
In 2010 we drilled 14 development wells. We completed eight of the wells drilled during the year plus one well drilled in late 2009. Two wells were not completed due to mechanical failure, three were dry holes and one is still being evaluated. In our production optimization program we performed 20 recompletions, 29 sliding sleeve changes, 7 gas lift modifications, 1 acid job and 1 water shut-off. At year-end 2010, we had 65 proved undeveloped locations in this field. Our planned 2011 capital expenditures in the field will include drilling 4 to 5 wells and performing recompletions on at least 10 wells.
Bay de Chene. The Bay de Chene field is located along the border of Jefferson Parish and Lafourche Parish in nearshore waters approximately 25 miles from the Lake Washington field. As of December 31, 2010, we owned drilling and production rights in approximately 14,673 net acres in the Bay de Chene field. Like Lake Washington, it produces from Miocene sands surrounding a central salt dome. During 2010 we did not drill any wells in the Bay De Chene field. At year-end 2010, we had two proved undeveloped locations in the Bay de Chene field. During 2011, we plan to drill one to two wells in Bay de Chene.
Central Louisiana/East Texas
Burr Ferry. The Company has 32,724 net acres in the Burr Ferry field predominately located in Vernon Parish, Louisiana. Most of this acreage is within an area covered by a joint venture agreement with a large independent oil and gas producer. We entered into this joint venture agreement in 2009 for development and exploitation. In addition to holding a 50% working interest in the joint venture, the Company is also the fee mineral owner in most of this acreage. During 2010 the Company drilled and completed the first two non-operated wells in this joint venture. The reserves are approximately 65% oil and NGLs. We have identified 10 additional proved undeveloped locations in this field, and plan to drill up to four wells in this field in 2011.
Masters Creek. As of December 31, 2010, we owned drilling and production rights in 56,251 net acres and approximately 35,000 unleased fee mineral acres in the Masters Creek field. The Masters Creek field, located in Vernon Parish and Rapides Parish, Louisiana, consists of opposing dual lateral horizontal wells completed in the Austin Chalk formation. Oil and natural gas are produced from natural fractures encountered within the lateral borehole sections from depths of 11,500 to 13,500 feet. The reserves are approximately 71% oil and NGLs. At year-end 2010, we had seven proved undeveloped locations. We deferred plans to drill a well in Masters Creek during 2010 and have tentatively rescheduled the well for drilling in the second half of 2011.
South Bearhead Creek. The South Bearhead Creek field is located in Beauregard Parish, Louisiana approximately 50 miles south of our Masters Creek field and 30 miles north of Lake Charles, Louisiana. The field was discovered in 1958 and is a large east-west trending anticline closure with cumulative production of over 4 million Boe. As of December 31, 2010, we owned drilling and production rights in 6,425 net acres in this field. Wells drilled in this field are completed in a multiple set of separate sands: Lower Wilcox - 12,500 to 14,500 feet; Middle and Upper Wilcox – 9,000 to 12,000 feet; and Cockfield – 8,000 to 9,000 feet. In 2010, we did not drill any wells in this field. At year-end 2010 we had 18 proved undeveloped locations in this field.
Brookeland. The Brookeland field area is located in Newton County and Jasper County, Texas, and Vernon Parish, Louisiana. As of December 31, 2010, we owned drilling and production rights in 69,540 net acres in this field. The field consists of opposing dual lateral horizontal wells completed in the Austin Chalk formation. Oil and natural gas are produced from natural fractures encountered within the lateral borehole sections from depths of 11,500 to 13,500 feet. The reserves are approximately 57% oil and natural gas liquids. During 2010 we drilled and completed one operated and one non-operated well in this field. At the end of 2010 we had no proved undeveloped locations in the field.
Cote Blanche Island. The Cote Blanche Island field is located in nearshore waters within St. Mary Parish. As of December 31, 2010, we owned drilling and production rights in 6,059 net acres in the Cote Blanche Island field. Similar to Lake Washington and Bay de Chene, it produces from Miocene sands surrounding a central salt dome. During 2010 we did not drill any wells in the Cote Blanche Island field, and at year-end 2010 we had three proved undeveloped locations in the field.
Bayou Sale, Horseshoe Bayou, Jeanerette, and Bayou Penchant. In October 2006 we acquired interests in four additional onshore fields in the area: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), and Bayou Penchant field in Terrebonne Parish. As of December 31, 2010, we owned drilling and production rights in a total of 18,637 net acres in these fields (5,700 in Bayou Sale, 5,138 in Horseshoe Bayou, 4,913 in Jeanerette, and 2,886 in Bayou Penchant). Bayou Sale and Horseshoe Bayou fields are adjacent to each other and located 13 miles southeast of our Cote Blanche Island field. They produce from several formations. The Jeanerette field is positioned on the flank of a large salt dome 12 miles north of Cote Blanche Island and produces form the Planulina sands. The Bayou Penchant field was discovered in the 1930s and is located approximately 44 miles southeast of Cote Blanche Island in Terrebonne Parish. Swift Energy holds an average 43% working interest in the wells in this non-operated field, which produces from a number of Middle Miocene sands.
In 2010, we did not drill any wells in our Bayou Sale, Horseshoe Bayou and Jeanerette fields. At year-end 2010, we had 24 proved undeveloped locations in the Bayou Sale, Horseshoe Bayou and Jeanerette fields.
Four Corners. At the end of 2010, we had approximately 20,069 net acres leased in the Four Corners area of southwest Colorado.
New Zealand Areas (Discontinued Operations)
In December 2007, we agreed to sell substantially all of our New Zealand assets. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of operations and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. In June 2008, we completed the sale of substantially all of our New Zealand assets for $82.7 million in cash after purchase price adjustments. Proceeds from this asset sale were used to pay down a portion of our credit facility. In August 2008, we completed the sale of our remaining New Zealand permit for $15.0 million; with three $5.0 million payments to be received nine months after the sale, 18 months after the sale, and 30 months after the sale. All payments under this sale agreement are secured by unconditional letters of credit, with the first two payments received in February 2009 and February 2010, respectively. Due to ongoing litigation, we have evaluated the situation and determined that certain revenue recognition criteria have not been met at this time for the permit sale, and have deferred the potential gain on this property sale pending further development of this litigation.
In accordance with guidance contained in FASB ASC 360-10, the results of operations for the New Zealand operations have been excluded from continuing operations and reported as discontinued operations for the current and prior periods. Furthermore, the assets included as part of this divestiture have been reclassified as held for sale in the consolidated balance sheets.
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 domestically as of December 31, 2010, 2009, and 2008. The information set forth in the tables regarding reserves is based on proved reserves reports prepared by us. Our Director of Reserves & Evaluations, the primary technical person responsible for overseeing the preparation of our reserves estimates, is a Licensed Professional Engineer, holds a bachelor’s and a master’s degree in chemical engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and has over 20 years of experience supervising or preparing reserves estimates. H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers, has audited 98% of our 2010 domestic proved reserves, 96% of our domestic proved reserves for 2009 and 97% of our domestic proved reserves for 2008. The audit by H.J. Gruy and Associates, Inc. conformed to the meaning of the term “reserves audit” as presented in Regulation S-K, Item 1202. The technical person at H.J. Gruy and Associates, Inc. primarily responsible for overseeing the audit, is a Licensed Professional Engineer, holds a degree in petroleum engineering, is past Chairman of the Gulf Coast Section of the Society of Petroleum Engineers, is past President of the Society of Petroleum Evaluation Engineers and has over 20 years experience overseeing reserves audits. Based on its audits, it is the judgment of H.J. Gruy and Associates, Inc. that Swift Energy used appropriate engineering, geologic, and evaluation principles and methods that are consistent with practices generally accepted in the petroleum industry.
The reserves estimation process involves reserves coordinators who are senior petroleum reservoir engineers whose duty is to prepare estimates of reserves, in accordance with the Commission’s rules, regulations and guidelines, and who are part of multi-disciplinary teams responsible for each of the Company’s major core asset areas. The multi-disciplinary teams consist of experienced reservoir engineers, geologists and other oil and gas professionals. Each reserves coordinator involved in the reserves estimation process has a minimum of 10 years reservoir engineering experience. The Director of Reserves and Evaluations supervises this process with multiple levels of review and reconciliation of reserves estimates to ensure they conform to SEC guidelines. Reserves data is also reported to and reviewed by senior management and the Board of Directors on a periodic basis. At year-end a reserves audit is performed by the third-party engineering firm, H.J. Gruy and Associates, Inc., to ensure the integrity and reasonableness of our reserves estimates. In addition, our independent Board members meet with H.J. Gruy and Associates, Inc. in executive session at least annually to review the annual audit report and the overall audit process
A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the U.S. Securities and Exchange Commission within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
Estimates of future net revenues from our proved reserves and their PV-10 Value, for the years ended December 31, 2010 and 2009, are made based on either the preceding 12-months’ average price based on closing prices on the first business day of each month, excluding 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 natural gas contracts, the use of fixed and determinable contractual price escalations. For the year ended December 31, 2008, these same amounts are based on the same methodology except for the use of period-end oil and gas sales prices. 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 12-month average 2010 prices for domestic operations were $4.08 per Mcf of natural gas, $78.31 per barrel of oil, and $42.01 per barrel of NGL compared to $3.78 per Mcf of natural gas, $59.76 per barrel of oil, and $30.00 per barrel of NGL at year-end 2009 and $4.96 per Mcf of natural gas, $44.09 per barrel of oil, and $25.39 per barrel of NGL at year-end 2008.
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 their PV-10 Value as of December 31, 2010, 2009, and 2008. 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. 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 (MBoe amounts shown below are based on a natural gas conversion factor of 6 Mcf to 1 Boe):
The PV-10 values for 2010, 2009, and 2008 are net of $82.3 million, $64.2 million, and $48.8 million of asset retirement obligation liabilities, respectively
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 natural 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 natural 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 natural 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 natural gas reserves.
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 natural 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 provides a reconciliation between PV-10 and the standardized measure of discounted future net cash flows:
Domestic Proved Undeveloped Reserves
The following table sets forth the aging and PV-10 value of our domestic proved undeveloped reserves as of December 31, 2010:
During 2010, we recorded 27.4 MMBoe of additional proved undeveloped reserves based on the results of the drilling program conducted during the year, primarily in the South Texas area. We also spent approximately $74.7 million in capital expenditures during the year to convert proved undeveloped reserves to proved developed reserves in the AWP and Lake Washington fields, resulting in the conversion of 5.4 MMBoe to proved developed reserves. As of December 31, 2010, approximately 1% of our total proved reserves consisted of undeveloped reserves added prior to 2005 in the Lake Washington field. The conversion of proved undeveloped reserves to proved developed reserves in recent years has been delayed by significant external factors, including the impacts of multiple hurricanes in key operating areas and restricted access to hydraulic fracturing services, rental equipment and related completion services in South Texas.
Sensitivity of Domestic Reserves to Pricing
As of December 31, 2010, a 5% increase in oil and NGL pricing would increase our total estimated domestic proved reserves of 132.8 MMBoe by approximately 0.2 MMBoe, and would increase the PV-10 Value of $1.8 billion by approximately $115 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated domestic proved reserves by approximately 0.2 MMBoe and would decrease the PV-10 Value by approximately $116 million.
As of December 31, 2010 a 5% increase in natural gas pricing would increase our total estimated domestic proved reserves by approximately 0.1 MMBoe and would increase the PV-10 Value by approximately $46 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated domestic proved reserves by approximately 0.2 MMBoe and would decrease the PV-10 Value by approximately $46 million.
Oil and Gas Wells
The following table sets forth the total gross and net wells in which we owned an interest at the following dates:
Oil and Gas Acreage
The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2010:
As of December 31, 2010, Swift Energy’s net undeveloped acreage subject to expiration over the next three years, if not renewed, is approximately 11% in Year 1, 27% in Year 2 and 37% in Year 3. In most cases, acreage scheduled to expire can be held through drilling operations or we can exercise extension options.
Drilling and Other Exploratory and Development Activities
The following table sets forth the results of our drilling activities during the three years ended December 31, 2010:
Ten of the 11 exploratory wells were Eagle Ford appraisal test wells. The one exploratory dry well was an Olmos horizontal test well that encountered significant hydrocarbons but could not be completed due to mechanical failure.
As of December 31, 2010 we had 3 drilling rigs under contract working in South Texas and one in Lake Washington. Two non-operated wells were also being drilled at year-end, one in South Texas and one in Brookeland. Completion operations have been ongoing and all but one of the wells drilled before year-end have been subsequently completed. We have also continued the production optimization program in the Lake Washington field, involving gas lift enhancements and sliding sleeve shifts to change productive zones, to assist in mitigating natural field declines.
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 natural gas properties.
Operations on our oil and natural gas properties are customarily administrated in accordance with COPAS guidelines. We charge a monthly per-well supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. 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 2010 totaled $12.5 million and ranged from $374 to $2,943 per well per month.
Fixed and Determinable Commitments
As of December 31, 2010 we had commitments to deliver fixed and determinable quantities of natural gas under term contracts as follows:
The sales price is tied to current spot gas prices at the time of delivery. Delivery quantities in excess of the minimums for any given year will proportionally reduce the minimum quantities for subsequent periods. The delivery point is in South Texas, and the Company’s proven reserves and production rates in the area significantly exceed the minimum obligations. There is no dedication of production from specific leases under the agreement.
Marketing of Production
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. Shell Oil Company and its affiliates accounted for approximately 52 %, 48% and 28% of our gross oil and gas sales in 2010, 2009 and 2008, respectively. In 2008, Chevron Corporation and its domestic affiliates accounted for 25% of our gross oil and gas sales. No other purchasers accounted for more than 10% of our total oil and gas sales for the past three years. Due to the demand for oil and natural gas and the availability of other purchasers, we do not believe that the loss of any single oil or natural gas purchaser or contract would materially affect our revenues.
Our oil production from the Lake Washington field is either 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 field 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. Natural gas delivered into Tennessee Gas Pipeline is processed at the Yscloskey plant. In 2008, we completed a connection which provides for the delivery of natural gas from this field to El Paso’s Southern Natural Gas pipeline system (Sonat) and for the processing of natural gas delivered to Sonat at the Toca Plant.
In 2008, we entered into gas processing and gas transportation agreements for our natural gas production in the AWP field with Enterprise Hydrocarbons L.P. and Enterprise South Texas Pipeline, replacing the ten-year agreements with Enterprise that expired in 2008. Processing revenues are received from Enterprise. The residue gas is sold at downstream connections with the Enterprise pipeline at prevailing market prices. Oil production is transported to market by truck or pipeline and sold at prevailing market prices.
In the Sun TSH and Fasken fields, our oil production is sold at prevailing market prices and transported to market by truck. Natural gas from the fields has historically been delivered either to Enterprise South Texas Gathering or Regency Gas Services. For natural gas delivered to Enterprise, the natural gas is sold to Enterprise; with Swift Energy receiving revenues from residue gas sales and processed liquids. For natural gas delivered to Regency, the natural gas production is transported to a downstream processing plant. We sell the residue gas at prevailing market prices and receive processing revenues from Regency. In the fourth quarter of 2010, Meritage Midstream Services, LLC completed construction of a new pipeline to the Fasken area. We entered into a gathering agreement providing for the transportation of our Eagle Ford production on the new pipeline from Fasken to Kinder Morgan Texas Pipeline, where it is sold at prices tied to monthly and daily natural gas price indices.
Our oil production from the Brookeland, Masters Creek and South Bearhead Creek fields is sold to various purchasers at prevailing market prices. Our natural gas production from the Brookeland and Masters Creek fields 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 natural gas production is sold into the interstate market on Trunkline Gas Company’s pipeline at prevailing market prices. There is field level extraction of a portion of the NGL’s in the gas stream prior to delivery to Trunkline. Those NGL’s are stored in a pressurized vessel and transported by truck to market for sale 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. Natural gas production from both fields is sold into intrastate pipelines with prices tied to monthly and daily natural gas price indices.
In the fields of Bayou Sale, Horseshoe Bayou, High Island and Jeanerette in South Louisiana, we sell the oil production to various purchasers at prevailing market prices. The oil is transported to market by truck. Natural gas production for each of these fields is sold into one or more interstate pipelines at prevailing market prices.
The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production from our continuing operations for the three-year period ended December 31, 2010:
(1) Excludes gas consumed in operations that is included in reported production volumes
(2 )Excludes severance and ad valorem taxes
Oil and natural gas prices declined significantly in the latter part of 2008 from levels earlier in the year, and the average sales prices for 2008 are not indicative of prices in effect at the end of 2008. The prices above also do not include the effects of hedging. Quarterly prices and hedge adjusted pricing are detailed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K.
The following table provides a summary of our production, average sales prices, and average production costs for our AWP Olmos and Eagle Ford fields. These fields account for approximately 38% of the Company’s proved reserves based on total Boe as of December 31, 2010:
(1) Excludes gas consumed in operations that is included in reported production volumes
(2) Excludes severance and ad valorem taxes
Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, fires, and adverse weather conditions, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil spills, natural 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. See “1A. Risk Factors” of this report for more details and for discussion of other risks. We maintain comprehensive insurance coverage, including general liability insurance, operators extra expense insurance, and property damage insurance. Our standing Insurable Risk Advisor Team, which includes individuals from operations, drilling, facilities, reserves, legal, HSE and finance meets regularly to evaluate risks, review property values, review and monitor claims, review market conditions and assist with the selection of coverages. 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. See Item 1A – Risk Factors.
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 natural gas prices, mainly through the purchase of price floors and participating collars when appropriate. At December 31, 2010, we had natural gas price floors in effect that covered a portion of our natural gas production for January to April 2011. These floors cover production of 4,250,000 MMBtu from January through April 2011 with strike prices ranging between $3.77 and $4.30 per MMBtu.
We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural 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 natural 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 ability to replace and expand our reserves base depends on our continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling and acquisition.
Some of our properties are located on federal oil and natural 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.
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 natural 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. We have further discussed our New Zealand litigation in footnote 8 of the notes to consolidated financial statements (“Discontinued Operations”).
At December 31, 2010, we employed 292 persons. None of our employees are represented by a union. Relations with employees are considered to be good.
At December 31, 2010, we occupied approximately 202,355 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring February 2015. The lease requires payments of approximately $450,000 per month. We also have field offices in various locations from which our employees supervise local oil and natural gas operations.
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.
Item 1A. Risk Factors
The nature of the business activities conducted by Swift Energy subjects it to certain hazards and risks. The following is a summary of all the material risks relating to our business activities.
Our future revenues, net income, cash flow, 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 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, currency exchange rates, and political conditions in major oil producing regions, especially the Middle East. A significant decrease in price levels for an extended period would negatively affect us in several ways:
Consequently, our revenues and profitability would suffer.
Numerous legislative and regulatory proposals affecting the oil and gas industry have been proposed or are under consideration by the Obama administration, Congress and various federal agencies. Among these proposals are: (1) climate change legislation introduced in Congress, Environmental Protection Agency regulations, carbon emission "cap-and-trade" regimens, and related proposals, none of which have been have been adopted in final form; (2) proposals contained in the President's budget, along with legislation introduced in Congress, none of which have been enacted by both houses of Congress, to repeal various tax deductions or exemptions available to oil and gas producers, such as the tax deduction for intangible drilling and development costs, which if eliminated could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; and (3)legislation being considered by Congress that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act, which could affect Company operations, their effectiveness, and the costs thereof. Any such future laws and regulations could result in increased costs or additional operating restrictions, and could have an effect on demand for oil and gas or prices at which it can be sold. Until any such legislation or regulations are enacted or adopted, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.
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 reserves 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 reserves 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, 2010, approximately 55% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserves data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur.
Approximately 27% of our 2010 reserves and 52% of our 2010 production are located in our South Louisiana and Southeast Louisiana core areas. Hurricane activity in 2007 and 2008 resulted in production curtailments and physical damage to our Gulf Coast operations. For example, a significant percentage of our production was shut down by Hurricanes Katrina and Rita in 2005, and by Hurricanes Gustav and Ike in 2008. Due to increased costs after the 2005 hurricanes, we no longer carry business interruption insurance. If hurricanes damage the Gulf Coast region where we have a significant percentage of our operations, our cash flow would suffer. This decrease in cash flow, depending on the extent of the decrease, could reduce the funds we would have available for capital expenditures and reduce our ability to borrow money or raise additional capital.
As extensively reported, global credit and financial markets experienced extreme disruptions beginning in the second half of 2008, severely diminishing liquidity and credit availability, volatility in consumer confidence, declines in economic growth, increases in unemployment rates, and uncertainty about economic stability. We cannot assure you that there will not be further deterioration in credit, financial, or commodities markets. These economic conditions have led to higher volatility for crude oil and natural gas prices, as demonstrated by the decline in commodity prices which occurred during the later part of 2008 and into 2009. Our profitability will be significantly affected by decreased demand and lower commodity prices. Our future access to capital and the availability of future financing could be limited due to tightening credit markets that could affect our ability to fund our capital projects.
Global economic conditions may adversely affect the financial viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have heightened our level of scrutiny of our contractual counterparties, our assessment of the risk of non-performance by various parties is subject to sudden swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and future insurance claims that we may have.
Our future access to capital could be limited due to tightening credit markets that could affect our ability to fund our future capital projects. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our line of credit or cause them to make the terms of our line of credit costlier or more restrictive. We are subject to semi-annual reviews of our borrowing base and commitment amount under our line of credit, and do not know the result of future redeterminations or the effect of then current oil and gas prices on that process. Additionally, our line of credit matures in October 2015, and although it has a zero balance as of December 31, 2010, long-term restriction or freezing of the capital markets may affect the availability or pricing of our renewal of the line of credit.
The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment. Starting with our financial statements ending December 31, 2009 the unescalated prices are calculated under the rules using a twelve month rolling average price from the first business day of each month. Any capital costs in excess of the ceiling must be permanently written down. Low oil and gas prices at December 31, 2008 and March 31, 2009 led to $473.1 and $50.0 million non-cash after-tax write-downs of our oil and gas properties, respectively. If oil and gas prices decline in the future, to the degree such that we incur additional capital costs on oil and gas properties and add proved reserves, we may be required to record further write-downs of our oil and gas properties in subsequent periods.
These risks include blowouts, explosions, adverse weather effects and pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
As of December 31, 2010, our total debt comprised approximately 35% 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. Higher levels of indebtedness could negatively affect us by requiring us to dedicate a substantial portion of our cash flow to the payment of interest, and limiting our ability to obtain financing or raise equity capital in the future.
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 reserves estimates and the number of economically viable prospects that we have to drill.
Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. 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 natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.
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:
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, as is the case in our declining business interruption insurance following the hurricanes in 2005. 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.
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.
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 natural 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 and Texas, 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.
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 much lower after we complete a well than when we identified it as a prospect, the completed well may not yield commercially viable quantities.
As is customary in the industry, we generally acquire oil and natural 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.
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, although we typically enter into only short-term hedges covering less than 50% of our anticipated production, which limits the price protection they provide. Our hedges at year-end 2010 consisted of natural gas price floors with strike prices ranging between $3.77 and $4.30. Our hedging transactions have also historically 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 when appropriate. 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 operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural 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 natural 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. As demand increases for equipment, services, and personnel, we may experience increased costs and various shortages and may not be able to obtain the necessary oilfield services and trained personnel.
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.
Our 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 on our operations and financial position.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In December 2009, the EPA issued an “endangerment and cause or contribute finding” for greenhouse gases under section 202(a) of the Clean Air Act, which will allow the EPA to adopt rules under the CAA that directly regulate greenhouse gases. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010 and, most recently, on November 8, 2010, adopted amendments to this rule expanding the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmissions, storage and distribution facilities, beginning in 2012 for emissions occurring in 2011.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, primarily through means of a cap and trade program that would require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. More than one-third of the states (but not currently including Louisiana or Texas) either individually or through multi-state initiatives already have begun implementing legal measures to reduce or report upon emissions of greenhouse gases. Any adoption of legislation or new regulations imposing reporting obligations upon, or limiting emissions of greenhouse gases from, our equipment and operations could adversely impact our business, result in increased compliance costs or additional operating restrictions, and have an adverse effect on demand for the oil and natural gas we produce.
Legislation introduced in Congress last year called the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” would repeal an exemption in the federal Safe Drinking Water Act (“SWDA”) for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available and make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure of chemicals used in the fracturing process, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing disclosure obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, increase our costs of compliance, cause delays in permitting, and adversely affect our business.
The Safe Drinking Water Act, as amended, currently excludes hydraulic fracturing from EPA regulation so long as no diesel fuel is used in the fracturing process. Recent Congressional investigations have shown that despite the absence of permits being issued for diesel fuel use in fracturing, a number of companies have acknowledged incorporating diesel fuel into their fracturing fluids. Should the EPA decide that companies using diesel fuel in fracturing operations are in violation of the Safe Drinking Water Act, penalties could be imposed on those companies, possibly retroactive in nature. Enhanced EPA regulation of fracturing could impose additional costs on the operations of the Company, alter the effectiveness of fracturing as currently conducted, and alter development plans using the fracturing process. The vendors which the Company contracts with do not currently use diesel fuel in their fracturing fluids.
Our 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 operations that have been used for the exploration and production of oil and natural 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 operations in Louisiana state waters 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 water based facilities in Louisiana 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 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.
United States Federal and State 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.
Since December 2007, Congress has passed the Energy Independence and Security Act of 2007, the Energy Economic Stabilization Act of 2008, and the American Recovery and Reinvestment Act of 2009, each of which contains various provisions affecting the oil and gas industry and related tax provisions. In future periods, Congress may decide to revisit legislation introduced in prior sessions to repeal existing incentives or impose new taxes on the exploration and production of oil and natural gas, and/or create new incentives for alternative energy sources. If enacted, such legislation could reduce the demand for and uses of oil, natural gas and other minerals and/or increase the costs incurred by the Company in its exploration and production activities, which could affect the Company’s revenues, costs, and profits.
Production of any oil and natural 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 natural gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and natural gas and to protect correlative rights to produce oil and natural gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and natural 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.
Item 1B. Unresolved Staff Comments
Glossary of Abbreviations and Terms
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business. We have further discussed our New Zealand litigation in footnote 8 of the notes to consolidated financial statements (“Discontinued Operations”)
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2010 to a vote of security holders.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock, 2009 and 2010
Our common stock is traded on the New York Stock Exchange under the symbol “SFY.” The high and low quarterly closing sales prices for the common stock for 2009 and 2010 were as follows:
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 183 stockholders of record as of December 31, 2010.
Stock Repurchase Table
The following table summarizes repurchases of our common stock occurring during the fourth quarter of 2010:
Equity Compensation Plan Information
The table summarizing information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2010 is located in Note 6 of Notes to Consolidated Financial Statements.
Share Performance Graph
The following Share Performance Graph shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
(1) Amounts have been retroactively adjusted in all periods presented to give recognition to: (a) discontinued operations related to the sale of our New Zealand oil & gas assets, and (b) the conversion of production and reserves volumes to a Boe basis.
(2) These prices do not include the effects of our hedging activities which were recorded in “Price-risk management and other, net” on the accompanying statements of operations. The hedge adjusted prices are detailed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K. Natural gas sales prices represents the amount realized per MCF of production.
Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the years ended December 31, 2009, 2008, and 2007 included with this report. Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management’s Discussion and Analysis relates solely to our continuing operations located in the United States, and excludes our New Zealand discontinued operations. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 39 of this report.
We are an independent oil and natural gas company formed in 1979, and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from our Texas properties as well as onshore and inland waters of Louisiana. We are one of the largest producers of crude oil in the state of Louisiana, and hold a large acreage position in Texas prospective for liquids-rich Eagle Ford shale and Olmos tight sands development. Oil production accounted for 47% of our 2010 production and 71% of our oil and gas revenues, and combined production for both oil and natural gas liquids (“NGLs”) made up 61% of our 2010 production and 82% of our oil and gas sales. This emphasis has allowed us to benefit from better margins for oil production than natural gas production during 2010.
Increases in Earnings and Cash Flow. Our year-to-year income from continuing operations increased by $85.6 million and cash provided by operating activities increased by $32.8 million, as oil and NGL prices received in 2010 were 32% and 35% higher, respectively, than the average prices we received in 2009, while natural gas prices increased 14% in 2010.
Improved Liquidity at Year-End 2010. In November 2010, we raised $140.1 million net through an underwritten public stock offering of 4.0 million shares of our common stock at a price of $36.60 per share. This followed an equity offering in the third quarter of 2009 when we raised $108.8 million net in the sale of 6.21 million shares of our common stock at a price of $18.50 per share. Taken together with $300.0 million of borrowing capacity under our credit agreement at December 31, 2010, our improved liquidity provides capital, if needed, for our expanded 2011 drilling program.
Increased Reserves. Year-end 2010 total proved reserves increased 18%, or 19.9 MMBoe over reserves quantities at December 31, 2009, with a year-end 2010 PV-10 value increasing by approximately $450 million to $1.8 billion.
South Texas Drilling. During 2010 we drilled 32 horizontal wells and an additional 6 vertical wells helping us evaluate Eagle Ford and Olmos acreage positions in our South Texas area. At year-end, our South Texas core area surpassed Southeast Louisiana in terms of both production and proven reserves. We also entered into long-term agreement with a major industry service provider for South Texas, securing access to fracing services at competitive prices for a two-year period.
Shareholder Return. We had annual shareholder return during 2010 of 63%.
Development Joint Ventures. Over the last 15 months we have entered into joint venture agreements with large independent oil and gas producers covering acreage in both our AWP and Burr Ferry fields, allowing us to both monetize a portion of our significant acreage positions (including a 26,000 acre portion of our Eagle Ford Shale acreage in McMullen County, Texas) and share costs of development drilling in these fields in order to accelerate their development.
In 2011, we are focused on accelerating our pace of development in South Texas, improving our results through more efficient execution and exploiting other areas of our asset base. Our exposure to liquids rich production growth in South Texas, our oil production in South Louisiana, our growing leasehold acreage in the Austin Chalk and our deep exploration prospect inventory along the Gulf Coast together provide a uniquely positioned resource portfolio for investors to evaluate. For 2011, we are targeting an increase in production volumes of 25% to 30% over 2010 levels and reserves growth of 15% to 20% over 2010 levels. The Company has also begun to explore entering into select joint venture arrangements to help accelerate the drilling and development of particular fields.
Results of Operations
Summary Prior Year Comparison
In 2010 we had revenues of $438.4 million, an increase of 18% compared to 2009 levels. Our weighted average sales price received increased 28% to $52.42 per Boe for 2010 from $41.05 per Boe in 2009. This $68.0 million increase in revenues from 2009 levels was due to higher oil, natural gas, and NGL prices during 2010, offset somewhat by an 8% decrease in production mainly due to natural declines in our Southeast Louisiana fields.
Our overall costs and expenses decreased in 2010 by $70.9 million when compared to 2009 levels, but were higher on a Boe basis, as the 2009 period included a non-cash write-down of our oil and gas properties of $79.3 million in the first quarter. Depreciation, depletion and amortization expense decreased 2%, mainly due to higher reserves volumes and lower production when compared to the 2009 period, partially offset by a higher depletable property base in the 2010 period. Lease operating costs increased by 7% due to higher workover costs, natural gas processing costs, and saltwater disposal costs. Severance and other taxes increased 11% mainly due to increased oil and gas revenues.
Our net income for 2010 was $46.3 million, while our net loss in 2009 was $39.3 million.
2010. Our revenues in 2010 increased by 18% compared to revenues in 2009 due to higher oil and gas prices after taking into account decreased production. Average oil prices that we received were 32% higher than those received during 2009, while natural gas prices were 14% higher, and NGL prices were 35% higher.
2009. Our revenues in 2009 decreased by 55% compared to revenues in 2008 primarily due to lower oil and gas prices, as oil, natural gas, and NGL prices we received in 2009 were 41%, 59%, and 45% lower, respectively, than the average prices we received a year earlier.
2008. Our 2008 production was adversely affected by Hurricanes Gustav and Ike. As a result of these hurricanes, approximately 0.8 MMBoe of production was shut-in during 2008 predominantly in Southeast Louisiana. All of this shut-in production was brought online in 2009.
Crude oil production was 47% of our production volumes in 2010, 48% in 2009, and 54% in 2008. Natural gas production was 39% of our production volumes in 2010, 39% in 2009, and 34% in 2008. The remaining production in each year was from natural gas liquids (NGLs).
Our properties are divided into the following four core areas, each of which includes the fields listed:
• South Texas
Hawkville Artesia Wells
• Southeast Louisiana
Bay de Chene
• Central Louisiana/East Texas
South Bearhead Creek
• South Louisiana
Horseshoe Bayou/Bayou Sale
Cote Blanche Island
The following table provides information regarding the changes in the sources of our oil and gas production and volumes for the years ended December 31, 2010, 2009, and 2008:
2010 Revenues Breakdown. Oil and gas sales in 2010 increased by 17%, or $64.9 million, from the level of those revenues for 2009, and our net production volumes in 2010 decreased by 8%, or 0.7 MMBoe, over net production volumes in 2009. Average prices for oil increased to $79.45 per Bbl in 2010 from $60.07 per Bbl in 2009. Average natural gas prices increased to $3.96 per Mcf in 2010 from $3.48 per Mcf in 2009. Average NGL prices increased to $42.44 per Bbl in 2010 from $31.36 per Bbl in 2009.
In 2010, our $64.9 million increase in oil, NGL, and natural gas sales resulted from:
2009 Revenues Breakdown. Oil and gas sales in 2009 decreased by 53%, or $422.1 million, from the level of those revenues for 2008, and our net production volumes in 2009 decreased by 10%, or 1.0 MMBoe, compared to net production volumes in 2008. Average prices for oil decreased to $60.07 per Bbl in 2009 from $101.38 per Bbl in 2008. Average natural gas prices decreased to $3.48 per Mcf in 2009 from $8.54 per Mcf in 2008. Average NGL prices decreased to $31.36 per Bbl in 2009 from $57.15 per Bbl in 2008.
In 2009, our $422.1 million decrease in oil, NGL, and natural gas sales resulted from:
The following table provides additional information regarding our quarterly oil and gas sales from continuing operations excluding any effects of our hedging activities: