Description
W&T Offshore. Chairman & CEO, 10% Owner TRACY W KROHN bought 50000 shares on 5-23-2012 at $ 15.03
BUSINESS OVERVIEW
W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983. We are an independent oil and natural gas producer, active in the acquisition, exploration and development of oil and natural gas properties primarily in the Gulf of Mexico and Texas.
The Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid return on our invested capital. We have leveraged our historic experience in the conventional shelf (water depths of less than 500 feet) to develop higher impact capital projects in the Gulf of Mexico in both the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet and water depths of less than 500 feet). We have acquired rights to explore and develop new prospects and acquired existing oil and natural gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional shelf.
During 2011, we significantly increased our activity onshore from what was previously a relatively minor presence. In May 2011, we acquired various properties and leasehold interests in four counties in the Permian Basin of West Texas (as described below) in a single transaction and separately acquired other leasehold interests in another county in the Permian Basin. In East Texas, we have acquired leasehold interests in two separate prospect areas. We have been actively exploring and developing each of these areas and have had up to eight drilling and workover rigs in service in our onshore operating areas during the year. We anticipate being active in both of these areas of Texas in 2012.
As of December 31, 2011, we have interests in offshore leases covering approximately 0.8 million gross acres (0.5 million net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama. Onshore, we have leasehold interests in approximately 0.2 million gross acres (0.2 million net acres), all of which are in Texas. Approximately 82% of our total net offshore acreage is developed and approximately 9% of our total net onshore acreage is developed. Of the onshore leasehold classified as undeveloped, almost all can be extended by drilling two additional wells in 2012 and further extended by additional operations or production in future years.
Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultant, our total proved reserves at December 31, 2011 were 116.9 million barrels of oil equivalent (“MMBoe”) or 701.1 billion cubic feet equivalent (“Bcfe”). Approximately 46% of our reserves were classified as proved developed producing, 19% as proved developed non-producing and 35% as proved undeveloped. Classified by product, our reserves at December 31, 2011 were 44% oil, 15% natural gas liquids (“NGLs”) and 41% natural gas. These percentages were determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. This conversion ratio does not assume price equivalency, and the prices for oil, NGLs and natural gas per Mcfe may differ significantly. During 2011, prices for oil were higher than NGLs and natural gas on a million cubic feet equivalent (“Mcfe”) basis, and prices for NGLs were higher than natural gas on a Mcfe basis. Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $3.1 billion. Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxes was $2.8 billion, and our standardized measure of discounted future cash flows was $2.0 billion as of December 31, 2011. For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserves under Part I, Item 2 of this Form 10-K .
We seek to increase our reserves through acquisitions, drilling, recompletions and workovers. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to add reserves, production and cash flow post-acquisition. Our acquisition team continues to work diligently to find properties that will fit our profile and that we believe will add strategic and financial value to our company.
As previously mentioned, in May 2011, we completed the acquisition of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the Permian Basin of West Texas, which we refer to as our “Yellow Rose Properties,” from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”). Based on internal estimates, the proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 MMBoe (180.4 Bcfe), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 70% of which were classified as proved undeveloped. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $394.4 million, and we assumed the ARO associated with the Yellow Rose Properties, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million.
In August 2011, we completed the acquisition of Shell Offshore Inc.’s (“Shell”) 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant (collectively, the “Fairway Properties”). Based on internal estimates, the proved reserves associated with the Fairway Properties as of the acquisition date were 8.9 MMBoe (53.5 Bcfe), comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and which are 100% proved developed. Including adjustments from an effective date of September 1, 2010, the adjusted purchase price was $42.9 million and we assumed the ARO associated with the Fairway Properties which we have estimated to be $7.8 million.
During 2010, we closed on two major acquisitions. In April 2010, we acquired two deepwater Gulf of Mexico fields (the “Matterhorn/Virgo Properties”) from Total E&P USA (“Total”) and in November 2010, we acquired three deepwater Gulf of Mexico fields (the “Tahoe/Droshky Properties”) from Shell.
Additional information on these acquisitions can be found in Properties under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and in Financial Statements – Note 2 – Acquisitions under Part II, Item 8 of this Form 10-K.
Our exploration efforts historically have been in areas in reasonably close proximity to known proved reserves, which we believe reduces our risks. Historically, we have financed our exploratory drilling with net cash provided by operating activities. The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure. Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelf and onshore. Certain risks are inherent in the oil and natural gas industry and our business, any one of which, if it occurs, can negatively impact our rate of return on shareholders’ equity. When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk. Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less than offshore wells. During the last three years, we have drilled eight, six and 10 successful offshore wells (gross) for the years 2011, 2010 and 2009, respectively and drilled 39 successful onshore wells (gross) in 2011.
From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. We did not sell any properties in 2011 or 2010. We are currently marketing a package of non-core properties located on the shelf of the Gulf of Mexico.
We generally sell our oil, NGLs and natural gas at the wellhead at current market prices or transport our production to “pooling points” where it is sold. We are required to pay gathering and transportation costs with respect to a majority of our products. Our products are marketed several different ways depending upon a number of factors including the availability of purchasers at the wellhead, the availability and cost of pipelines near the well or related production platforms, the availability of third-party processing capacity, market prices, pipeline constraints and operational flexibility.
Our total capital expenditure budget for 2012 is $425.0 million, not including any potential acquisitions. The budget includes $209.0 million to drill, evaluate and complete ten offshore wells (six exploration and four development wells) and $170.0 million to drill, evaluate and complete 65 onshore wells (19 exploration and 46 development wells). The budget also includes $46.0 million for facilities capital, recompletions, seismic and leasehold items. Thus far in 2012, we have not closed on any acquisitions and continue to evaluate and bid on opportunities as they arise. We anticipate funding our 2012 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand, borrowings under our revolving bank credit facility and by accessing the capital markets to the extent necessary. Our 2012 capital budget is subject to change as conditions warrant. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation and growth and managing the volatility inherent in our business.
Business Strategy
We plan to continue to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”), the area of our historical success and technical expertise, which we believe will yield rates of return sufficient to remain competitive in our industry. We believe attractive acquisition opportunities will continue to arise in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals. Because of ongoing market volatility and, more specifically, the significant decline in natural gas prices, we also believe that other less well-capitalized producers may seek buyers for their properties both onshore and offshore, which could create opportunities for us.
We believe a portion of our Gulf of Mexico acreage has exploration potential below currently producing zones, including deep shelf reserves at subsurface depths greater than 15,000 feet. Although the cost to drill deep shelf wells is usually significantly higher than shallower wells, the reserve targets are typically larger and the use of existing infrastructure, when available, can increase the economic potential of these wells.
In addition to pursuing opportunities in the Gulf of Mexico, we also plan to continue to pursue other areas that are compatible with our technical expertise and could yield rates of return sufficient to remain competitive in our industry. As described above, we have acquired interests in various onshore properties in Texas and anticipate acquiring or expanding our onshore holdings through acquisitions or exploration and development activities.
We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities. Historically, we have limited our annual capital spending for drilling activities to net cash provided by operating activities, and we have used capacity under our revolving bank credit facility for acquisitions and to balance working capital fluctuations.
Competition
The oil and natural gas industry is highly competitive. We currently operate in the Gulf of Mexico and Texas and compete for the acquisition of oil and natural gas properties primarily on the basis of price for such properties. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see Risk Factors in Part I, Item 1A of this Form 10-K .
Oil and Natural Gas Marketing and Delivery Commitments
We sell our oil, NGLs and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers. However, in 2011 we sold over 10% of our production to each of Shell Trading (US) Co., Conoco Phillips and JP Morgan Ventures Energy Corp. and these three companies accounted for approximately 62% of our total sales. See Financial Statements – Note 1 – Significant Accounting Policies – Concentration of Credit Risk in Part II, Item 8 of this Form 10-K for additional information about our sales to these customers. Due to the nature of oil and natural gas markets and because oil and natural gas are freely traded commodities with numerous purchasers in the Gulf of Mexico and Texas, we do not believe the loss of a single purchaser or a few purchasers would materially affect our ability to sell our production. We do not have agreements that obligate us to deliver certain quantities to third parties.
Regulation
General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
In addition, the Federal Trade Commission, the FERC and the Commodity Futures Trading Commission hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.
Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates. Similarly, the natural gas pipeline industry may also be subject to state regulations which may change from time to time. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the
requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset condition and proposals for certain changes were made, but no legislation was enacted during 2011 and the RRC will be reviewed again in 2013.
The Outer Continental Shelf Lands Act (“OCSLA”), which is administered by the Bureau of Ocean Energy Management (1) (“BOEM”) and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEM issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.
In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as W&T, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtus”) during a calendar year must annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
While the changes by these federal and state regulators for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.
Oil and natural gas liquids transportation rates . Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids, and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.
CEO BACKGROUND
Virginia Boulet , age 58, has served on the Board since March 2005. She is currently Chair of the Nominating and Corporate Governance Committee. She has been employed as Special Counsel to Adams and Reese, LLP, a law firm, since 2002. She is also an adjunct professor of law at Loyola University Law School. Prior to 2002, Ms. Boulet was a partner at the law firm Phelps Dunbar, LLP. Ms. Boulet has over 20 years of experience in mergers and acquisitions, equity securities offerings, general business matters and counseling clients regarding compliance with federal securities laws and regulations. Ms. Boulet currently serves on the board of directors of CenturyTel, Inc., a telecommunications company. Service on this board has provided her the background and experience of board processes, function, exercise of diligence and oversight of management. In the past, she served as President and Chief Operating Officer of IMDiversity, Inc., an on-line recruiting company. Ms. Boulet received a B.A. in Medieval History from Yale University, and a J.D., cum laude, from Tulane University Law School. With her public company board experience and recruiting experience as president of a recruiting company, Ms. Boulet is well suited to the Nominating and Corporate Governance Committee functions of identifying and evaluating individuals qualified to become board members and evaluating our corporate governance policies. Her legal background also provides her with a high level of technical expertise in reviewing transactions and agreements and addressing the myriad legal issues presented to the Board.
Samir G. Gibara , age 72, has served on the Board since May 2008. Mr. Gibara is the current Chair of our Compensation Committee and serves on the Audit Committee. Mr. Gibara is a private investor. He served as Chairman of the Board and Chief Executive Officer of The Goodyear Tire & Rubber Company (“Goodyear”) from 1996 to his retirement in 2002 and remained as non-executive chairman until June 30, 2003. Prior to 1996, Mr. Gibara served that company in various managerial posts before being elected President and Chief Operating Officer in 1995. Mr. Gibara is a graduate of Cairo University and holds a M.B.A. from Harvard University. Mr. Gibara also attended the Kellogg Graduate School of Management at Northwestern University. He has served on the boards of directors of Goodyear (1996 – 2003), Sumitomo Rubber Industries (1999 – 2002), Dana Corp. (2004 – 2008) and International Paper Company (1999 – 2011). Mr. Gibara is a member of the Investment Committee of the University of Akron Foundation. Mr. Gibara brings extensive business and management expertise to the Company from his background as Chief Executive Officer of Goodyear. Mr. Gibara also has considerable directorship experience having served as a director for several large public companies. We believe Mr. Gibara’s executive and educational background qualifies him for service as a member of our Board and Audit Committee and Chair of our Compensation Committee.
Robert I. Israel , age 62, has served on the Board since 2007. Mr. Israel serves on our Audit Committee. He is currently the Managing Partner of One Stone Energy Partners, a private equity fund, focused on investments in the oil and gas industry in the U.S. and abroad. From 2000 to 2010, Mr. Israel was a Partner at Compass Advisers, LLP, a transatlantic strategic advisory and private investment firm, where he was the head of the firm’s energy practice. From 1990 to 2000, Mr. Israel was the head of the Energy Department of Schroder & Co., Inc. Currently, Mr. Israel is a director of the following companies: Randgold Resources Limited, an African-based gold mining company; Brasoil, a company engaged in oil and gas exploration and production in Brazil; Suelopetrol C.A., a Venezuelan company engaged in seismic data gathering and exploration for oil and gas; Hart Energy Publishing, a trade publishing company covering the energy sector; and API, Inc. a company that manufactures secure equipment for U.S. and foreign government agencies. Mr. Israel holds a M.B.A. from Harvard University and a B.A. from Middlebury College. Mr. Israel, with over 30 years of corporate finance experience, has a strong business and financial background, especially in the natural resources sector. Mr. Israel’s corporate finance experience and his public company board experience, as well as his industry knowledge, make him a valuable addition to our Board and our Audit Committee.
Stuart B. Katz , age 57, previously served on the Board from 2002 to 2008 and was reappointed to serve on the Board in April 2011. Mr. Katz serves on our Audit and Compensation Committees. Since 2007, Mr. Katz has served as Chief Executive Officer of Alconox, Inc., a private company engaged in the manufacturing and marketing of specialty chemicals. From 2001 to 2010, Mr. Katz was a Managing Director of Jefferies Capital Partners (“JCP”), a private equity investment fund. In 2002, Mr. Katz joined the Board in connection with JCP’s investment in the Company. In May 2008, Mr. Katz declined to stand for reelection to the Board in connection with JCP’s divestment of its remaining equity interest in the Company. Prior to joining JCP in 2001, Mr. Katz had been an investment banker with Furman Selz LLC and its successors for over 16 years. Mr. Katz received a B.S. in engineering from Cornell University and a J.D. from Fordham Law School. Mr. Katz is a member of the bar of the State of New York. Mr. Katz also serves as a member of the boards of directors of several private companies. Mr. Katz brings valuable leadership and management skills as a result of his role as Chief Executive Officer of Alconox, as well as a result of his service as a member of the board of directors of a number of other companies, including other public companies. We believe that this experience, as well as the investment management experience he has gained through the ownership of controlling equity positions in connection with his activities with JCP, make him a valuable part of our Board and member of our Audit Committee and Compensation Committee.
Tracy W. Krohn , age 57, has served as Chief Executive Officer since he founded the Company in 1983, as President from 1983 until 2008, as Chairman of the Board since 2004 and as Treasurer from 1997 until 2006. He is also a member of the Nominating and Corporate Governance Committee. Mr. Krohn has been actively involved in the oil and gas business since graduating with a B.S. in Petroleum Engineering from Louisiana State University in 1978. He began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation. Prior to founding the Company, from 1982 to 1983, Mr. Krohn was senior engineer with Taylor Energy. From 1996 to 1997, Mr. Krohn was also Chairman and Chief Executive Officer of Aviara Energy Corporation in Houston, Texas. He also serves on the board of directors of a privately owned company. As founder of the Company, Mr. Krohn is one of the driving forces behind the Company and its success to date. Over the course of the Company’s history, Mr. Krohn has successfully grown the Company through his exceptional leadership skills and keen business judgment.
S. James Nelson , Jr., age 69, has served on the Board since January 2006. He is currently Chair of the Audit Committee and also serves as Presiding Director. In 2004, Mr. Nelson retired after 15 years of service from Cal Dive International, Inc., a marine contractor and operator of offshore oil and natural gas properties and production facilities, where he was a founding shareholder, Chief Financial Officer from 1990 to 2000, Vice Chairman from 2000 to 2004 and a director. From 1985 to 1988, Mr. Nelson was the Senior Vice President and Chief Financial Officer of Diversified Energies, Inc. and from 1980 to 1985 was the Chief Financial Officer of Apache Corporation, an oil and gas exploration and production company. From 1966 to 1980, Mr. Nelson was employed with Arthur Andersen & Co., where he became a partner in 1976. Mr. Nelson received a B.S. in Accounting from Holy Cross College and holds a M.B.A. from Harvard University. He is also a certified public accountant. Additionally, Mr. Nelson has served on the boards of directors and audit committees of Oil States International, Inc., a diversified oilfield service company, ION Geophysical (formerly Input/Output, Inc.), a seismic services provider and Genesis Energy, LP, a midstream master limited partnership which operates pipelines and provides services to refineries and industrial gas users. From 2005 until the company’s sale in 2008, he was also a member of the board of directors, Compensation Committee and Audit Committee of Quintana Maritime LTD, a provider of dry bulk shipping services based in Athens, Greece. Mr. Nelson has an extensive background in public accounting both from his time as a Partner at Arthur Andersen & Co. and his time as Chief Financial Officer at various companies. Mr. Nelson’s service on audit committees of other companies enables him to remain current on audit committee best practices and current financial reporting developments within the energy industry. We believe these experiences and skills qualify him to serve as the Chair of our Audit Committee.
B. Frank Stanley , age 57, has served on the Board since 2009. Mr. Stanley serves as a member of our Audit, Compensation and Nominating and Corporate Governance Committees. He is currently Co-Chief Executive Officer and Chief Financial Officer of Retail Concepts, Inc., a privately-held retail chain of 28 stores in 13 states with over seven hundred employees. Prior to joining Retail Concepts, Inc. in 1988, he was Chief Financial Officer of Southpoint Porsche Audi WGW Ltd. from 1987 to 1988. From 1985 to 1987, he was employed by KPMG Peat Marwick, holding the position of Manager, Audit in 1987. From 1983 to 1984, he was Chief Financial Officer of Design Research, Inc., a manufacturer of housing for offshore drilling platforms. From 1980 to 1982, he was Chief Financial Officer of Tiger Oilfield Rental Co., Inc. and, from 1977 to 1979, he was an accountant with Trunkline Gas Co. Mr. Stanley holds a B.B.A. in Accounting from Texas A&M University and is a certified public accountant. Mr. Stanley has an extensive background in accounting and financial matters, which qualify him for service as a member of our Board and Audit, Compensation, and Nominating and Corporate Governance Committees.
MANAGEMENT DISCUSSION FROM LATEST 10K
Overview
We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 58 producing and two capable of producing offshore fields in federal and state waters. During 2011, we expanded onshore into West Texas and East Texas through an acquisition and acquiring interests in leasehold acreage. We have interests in offshore leases covering approximately 0.8 million gross acres (0.5 million net acres) spanning primarily across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama and 0.2 million gross acres (0.2 million net acres) onshore in Texas. We operate wells accounting for approximately 80% of our average daily production. We own interests in approximately 253 offshore structures, 158 of which are located in fields that we operate.
In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on increasing production and reserves at a profit. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.
During the year 2011, we closed on two acquisition transactions. On May 11, 2011, we completed the acquisition from Opal of the Yellow Rose Properties, which consists of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the Permian Basin of West Texas. Based on internal estimates, proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 MMBoe (180.4 Bcfe), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 70% of which were classified as proved undeveloped. The stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011 until the closing date of May 11, 2011. Taking into account such adjustments, the adjusted purchase price was $394.4 million. The increase of $28.1 million primarily reflects drilling and development costs in excess of cash flow from the effective date of January 1, 2011 to the closing date. We assumed the ARO, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.
On August 10, 2011, we completed the acquisition of the Fairway Properties, which consist of Shell’s 64.3% working interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant. Based on internal estimates, proved reserves associated with the Fairway field as of the acquisition date were 8.9 MBoe (53.5 Bcfe) comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and which are 100% proved developed. The stated purchase price was $55.0 million, subject to certain adjustments, including adjustments from an effective date of September 1, 2010 until the closing date. Taking into account such adjustments, as of December 31, 2011, the purchase price was reduced to $42.9 million. The decrease of $12.1 million primarily reflects net production cash flow, partially offset by plugging and abandonment and other operating costs incurred, from the effective date of September 1, 2010 to the closing date. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first half of 2012. We assumed the ARO associated with the properties and plant, which we have estimated to be $7.8 million. The acquisition was funded from borrowings under our revolving bank credit facility.
During the year 2010, we closed on two acquisition transactions. The first was on April 30, 2010, when we acquired all of Total’s interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico. Estimates of proved reserves as of the acquisition date were 10.9 MBoe (65.6 Bcfe) comprised of approximately 58% oil, 6% NGLs and 36% natural gas and which are 69% proved developed. The adjusted purchase price was $121.3 million inclusive of the ARO estimated at $6.3 million. The acquisition was funded with cash on hand.
The second acquisition in 2010 was on November 3, 2010, when we acquired all of Shell’s interests, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico. Estimates of proved reserves as of the acquisition date were 13.3 MBoe (80.0 Bcfe) comprised of approximately 8% oil, zero NGLs and 92% natural gas and which are 100% proved developed. The adjusted purchase price was $134.2 million inclusive of the ARO estimated at $18.0 million. The acquisition was funded with cash on hand.
See Financial Statements – Note 2 – Acquisitions under Part II, Item 8 of this Form 10-K for additional information on acquisitions.
From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. We did not sell any properties in 2011 and 2010. We are currently marketing a package of non-core properties located on the OCS.
Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for 2011 were comprised of approximately 36% oil and condensate, 11% NGLs and 53% natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the prices per Mcfe for oil, NGLs and natural gas may differ significantly. For 2011, our combined total production of oil, NGLs and natural gas was approximately 16.7% higher on a Mcfe basis than during the same period in 2010.
The third-party pipeline used by our Main Pass 108 and 98 fields was shut down from June 2010 to March 2011. This impacted our production in 2011 and in 2010. By the end of the second quarter of 2011, production had been restored and has been positively impacted by various workover activities and significant field work, which included drilling both an exploration well and three development wells. In December 2011, these fields produced approximately 33.4 MMcfe per day, made up of 815 Bbls of oil per day, 538 Bbls of NGLs per day and 25.3 MMcf of natural gas per day.
During 2011, prices for oil were volatile and increased significantly compared to 2010. The majority of our oil production is priced using the posted spot price for West Texas Intermediate (“WTI”) as a base price plus a premium depending on the type of crude oil. WTI is frequently used to value domestically produced crude oil. Most of our oil production is from our offshore oil production, which is comprised of various crudes including Light Louisiana Sweet, Heavy Louisiana Sweet and Poseidon. Starting in the first quarter of 2011 and continuing through the end of 2011, these various crudes sold at a significant premium relative to WTI. In 2011 compared to 2010, our realized oil sales price (unhedged) increased 37.0%, compared to a 19.4% increase in the unweighted average daily posted spot price for WTI. The majority of our crude prices have correlated closer to the international oil market prices, as measured using the unweighted average daily posted spot price for Brent crude, which increased 39.8% in 2011.
The premiums received on our offshore oil production have been up to $30.00 per Bbl during times in 2011. In comparison, the average premium spread between Heavy Louisiana Sweet crude and WTI crude was approximately $2.00 per Bbl during 2010 and the average premium spread between Light Louisiana Sweet crude and WTI crude was approximately $3.00 per Bbl during 2010. According to industry sources, the correlation between North Sea Brent crude oil and WTI, the crude that trades on the New York Mercantile Exchange (“NYMEX”), had historically been extremely high. In fact, in the past, Brent crude oil has traded at a discount to WTI as Brent crude oil is a lower quality relative to WTI. In the middle of November of 2011, that correlation between the two crudes had fallen to its lowest level in twenty years. At the beginning of 2011, the price of crude oil at Cushing, Oklahoma, which is where the NYMEX WTI crude is priced, was pressured by an over supply situation. On the other hand, Brent prices were aided by supply disruptions due to unrest in the Middle East and oil production was halted in Libya. Since that time, the turmoil in Europe reduced oil demand and Libya’s oil production is returning. In addition, the announced reversal of the Seaway pipeline that has taken crude oil from the Gulf Coast to Cushing will begin flowing crude oil in Cushing to the Gulf Coast beginning in mid-2012. The price spread between Brent crude oil and WTI narrowed significantly on the day of this announcement. More recently, both WTI and Brent crude oil prices have increased with threats by Iran of closing the Strait of Hormuz and the implications of significantly reducing crude oil supplied from the region. If economic growth continues in China, India, Brazil and Russia, such activity will support strong crude oil prices. Also supporting higher prices is the fact that economic deterioration in the US and other countries has forced countries to adopt potentially inflationary policies which may raise the price of hard assets like crude oil and gold.
Natural gas prices are much more affected by domestic issues, such as supply, local demand issues and domestic economic conditions. During 2011, our average realized sales price of natural gas (unhedged) decreased 9.5% from 2010 compared to the benchmark Henry Hub unweighted average daily posted spot price, which decreased 8.5% from 2010. We expect continued weakness in natural gas prices at least through 2012 as producers continue to drill to hold leases, natural gas storage levels continue at record highs, winter weather continues to be relatively mild, production of natural gas as a by product of the substantial ramp up of oil drilling continues and production efficiency gains are achieved in the shale gas areas resulting from better fracking techniques. Potential mitigating factors could include an increase in demand if the United States experiences a strong economic recovery, a dramatic decrease in drilling activity, including horizontal oil well drilling, (which isn’t likely at current high oil prices) or production shut-ins due to economic factors. According to Baker Hughes data, the number of rigs drilling for oil has more than tripled since the beginning of 2009. There is also a risk that, as a result of successful exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas, increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. According to industry sources, use of directed horizontal drilling rigs is at record levels and is up over 20% in January 2012 compared to January 2011, while the total oil rig count is up over 50% in January 2012 compared to January 2011.
In 2011 and 2010, we did not incur an impairment write-down. Due to declines in oil, NGL and natural gas prices, in 2009 we recorded an impairment write-down of $218.9 million, as determined through the application of the ceiling test.
Should prices decline for oil and natural gas in the future, our future oil, NGL and natural gas revenues, earnings and liquidity would be negatively impacted, and could result in impairment write-downs of the carrying value of our oil and natural gas properties. This decline could create issues with financial ratio compliance, and could result in a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those factors were to occur and were significant, the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry in the future could be impacted.
Our operating costs include the expense of operating our wells, platforms and other infrastructure primarily in the Gulf of Mexico and Texas and transporting our production to the point of sale. Our operating costs are generally comprised of several components, including direct operating costs, repairs and maintenance, gathering and transportation costs, production taxes, workover costs and ad valorem taxes. Our operating costs depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties.
Revenue from our production is highly dependent on pipelines owned by others to access markets for our products. To the extent that the transportation price such pipelines charge increases, our revenues from the sales of our products would go down or transportation costs would increase, the result of either would be a reduction in operating income. Certain pipelines have filed tariffs which may increase the amounts charged to us and we believe that we have limited alternatives to use other pipelines. The approval process typically results in approval of fees less than those contained in the filing requests; therefore, at this time, we are unable to determine whether or when the rates may ultimately be increased and are unable to estimate the impact to operating income in 2012.
In recent years, we acquired and built platforms near the outer edge of the continental shelf and operated wells in the deepwater of the Gulf of Mexico. To the extent we continue our deepwater operations, our operating costs will likely increase. While each field can present operating problems that can add to the costs of operating a field, the production costs of a field are generally directly proportional to the number of production platforms built in the field. As technologies have improved, oil and natural gas can be produced from larger acreage areas using a single platform, which may reduce the operating costs associated with future development projects.
Our operations are exposed to potential damage from hurricanes and we obtain insurance to reduce our financial exposure risk. We incurred substantial costs from 2008 through 2011 for hurricane related damage occurring in 2008 and expect to incur costs through 2013 to complete plugging and abandonment work primarily related to three toppled platforms. We received reimbursements from our insurance carrier in each of the last three years and expect to receive additional reimbursements for covered costs incurred in future periods as covered costs incurred to date have not exceeded policy limits. See Liquidity and Capital Resources below and Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part II, Item 8 in this Form 10-K for additional information.
Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon all wells and to remediate any environmental damage our operations may have caused. The costs associated with our ARO generally increase as we drill wells in deeper parts of the continental shelf and in the deepwater. We generally do not pre-fund our ARO. We estimated the present value of our liability related to our ARO at $393.9 million as of December 31, 2011. Inherent in the present value calculation of our liability are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and expenditure, and changes in the legal, regulatory, environmental and political environments. Actual expenditures for ARO could vary significantly from these estimates.
In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico which caused loss of life, caused the rig to sink and created a major oil spill that produced economic, environmental and natural resource damage. Subsequently, the BOEM issued a series of NTLs and other significant changes in regulations and implemented a six-month moratorium on drilling activities which began in May 2010. After the drilling moratorium ended in November 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued, albeit at a slower and much more measured pace than before the Deepwater Horizon event. The most significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. The permitting process is also slow and inconsistent for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness or even at less than desirable times due to weather. We have not experienced delays in obtaining permits related to our onshore operations.
Results of Operations
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Revenues . Total revenues increased $265.3 million, or 37.6%, to $971.0 million in 2011 compared to 2010. Oil revenues increased $189.8 million, NGLs revenues increased $53.6 million, natural gas revenues increased $17.7 million and other revenues increased $4.2 million. The oil revenue increase was attributable to a 37.0% increase in the average realized sales price (unhedged) to $105.92 per Bbl in 2011 from $77.33 per Bbl in 2010, combined with an increase of 3.4% in sales volumes. The NGLs revenue increase was attributable to a 27.9% increase in the average realized sales price (unhedged) to $55.81 per Bbl in 2011 from $43.65 per Bbl in 2010, combined with an increase of 58.3% in sales volumes. The sales volume increase for oil and NGLs is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 20.1% increase in sales volumes, partially offset by a 9.5% decrease in the average realized natural gas sales price (unhedged). For 2011, the natural gas average realized sales price was $4.12 per Mcf compared to $4.55 per Mcf for 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the ONRR in 2010 of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this ONRR adjustment. For additional information, see Financial Statements – Note 19 – Contingencies under Part II, Item 8 of this Form 10-K.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $49.5 million to $219.2 million in 2011 compared to 2010. On a per Mcfe basis, lease operating expenses increased to $2.16 per Mcfe during 2011compared to $1.95 per Mcfe during 2010. On a component basis, base lease operating expenses, facility expenses, hurricane remediation costs net of insurance claims, and workover costs increased $20.7 million, $14.1 million, $11.7 million and $3.6 million, respectively. As a partial offset, insurance premiums decreased $0.6 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties and increased processing fees associated with our Daniel Boone field production. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in 2010. Workover costs increased due to work performed at our Yellow Rose Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not occur in 2011. The decrease in insurance premiums resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage that cover the policy period June 1, 2010 to June 1, 2011. Our premiums increased effective with the June 1, 2011 renewal attributable to a substantial improvement in coverage. For additional information, see Liquidity and Capital Resources – Hurricane Remediation and Insurance Claims.
Production taxes. Production taxes increased to $4.3 million during 2011 compared to $1.2 million in 2010 primarily due to the Yellow Rose Properties and the Fairway Properties’ operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.
Gathering and transportation costs. Gathering and transportation costs were basically flat for 2011 compared to the prior year.
Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, including accretion for ARO, decreased to $3.24 per Mcfe for 2011 from $3.38 per Mcfe for 2010. On a nominal basis, DD&A increased to $328.8 million for 2011 from $294.1 million in 2010. The decrease in DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.
General and administrative expenses. G&A increased to $74.3 million for 2011 from $53.3 million for 2010 due to a number of factors including higher incentive compensation as a result of improved financial and operational performance, costs related to expanded onshore and offshore activities, acquisitions, surety premiums, transition services fees paid to the sellers of the acquired properties, and litigation related costs. Also, we earned administration fees in 2010 related to an asset disposition, and no such fees were earned in 2011. On a per Mcfe basis, G&A was $0.73 per Mcfe for 2011, compared to $0.61 per Mcfe for 2010. See Financial Statements – Note 11 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 of this Form 10-K for additional information.
Derivative (gain) loss. For 2011, our derivative gain of $1.9 million was attributable entirely to a change in the fair value of our commodity derivatives as a result of the changes in crude oil prices. For 2010, our derivative loss of $4.3 million was attributable to a loss from our commodity derivatives of $4.0 million and a loss of $0.3 million related to our interest rate swap. See Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information.
Interest expense. Interest expense incurred increased to $52.4 million for 2011 from $43.1 million for 2010. During 2011, the amounts outstanding of our senior notes increased to $600.0 million from $450.0 million due to issuing our 8.5% Senior Notes and repurchasing our 8.25% Senior Notes. During 2011 and 2010, $9.9 million and $5.4 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased due to the Yellow Rose Properties acquisition. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.
Loss on extinguishment of debt . The loss on extinguishment of debt during 2011 of $22.7 million was attributable primarily to the repurchase of all of the $450.0 million outstanding of our 8.25% Senior Notes. The repurchase of the 8.25% Senior Notes was funded with a portion of the proceeds from the issuance of the 8.5% Senior Notes. The call premiums, unamortized debt issuance costs and other related expenses totaled $22.0 million. In addition, the previous revolving bank credit facility was amended and the termination date extended resulting in the write off of unamortized debt issuance costs of $0.7 million. In 2010, no loss on extinguishment of debt was incurred. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.
Interest income. Interest income decreased to $0.1 million for 2011 from $0.7 million in 2010 primarily due to lower average daily cash balances and a reduction in market interest rates received on invested cash in 2011.
Income tax expense (benefit). Income tax expense increased to $91.5 million for 2011 compared to $11.9 million for 2010. Our effective tax rate for 2011 was 34.6% and differed from the federal statutory rate of 35% primarily as a result of the deduction for qualified domestic production activities under Section 199 of the Internal Revenue Code (“IRC”). Our effective tax rate for 2010 was 9.2% and primarily reflects a reduction in our valuation allowance against our deferred tax assets and the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the IRC. Taxable income in 2010 allowed us to reverse all of our previously recorded valuation allowance.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Overview
We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 60 producing offshore fields in federal and state waters. During 2011, we expanded onshore into West Texas and East Texas where we are actively pursuing exploration and development activities. The majority of our daily production was derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.
Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, natural gas liquids (“NGLs”) and natural gas production and the prices that we receive for such production. Our production volumes for the first quarter of 2012 were comprised of approximately 34.4% oil and condensate, 12.1% NGLs and 53.5% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil, NGLs and natural gas may differ significantly. In the first quarter of 2012, revenues from the sale of oil and NGLs made up 83.2% of our total revenues, which is up from 75.6% in the first quarter of 2011. As the relationship between oil and natural gas prices continues to diverge, we expect that this trend could continue. For the first quarter of 2012, our combined total production of oil, condensate, NGLs and natural gas was approximately 18.4% higher on a Mcfe basis than during the same period in 2011.
During 2011, we closed on two acquisition transactions. On May 11, 2011, we completed the acquisition of the Yellow Rose Properties, which consist of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the Permian Basin of West Texas. Based on internal estimates, proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 million barrels of oil equivalent (“MMBoe”) (180.4 billion cubic feet equivalent (“Bcfe”)), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 30% of which were classified as proved developed. The adjusted purchase price was $394.4 million excluding ARO and long-term liabilities. We assumed the ARO, which we estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.
On August 10, 2011, we completed the acquisition of the Fairway Properties, which consisted of a 64.3% working interest in the Fairway field along with a like interest in the associated Yellowhammer gas treatment plant. Based on internal estimates, proved reserves associated with the Fairway field as of the acquisition date were 8.9 MMBoe (53.5 Bcfe) comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and which are 100% proved developed. As of March 31, 2012, the adjusted purchase price was $42.9 million excluding ARO. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first half of 2012. We assumed the ARO associated with the properties and plant, which we estimated to be $7.8 million. The acquisition was funded from borrowings under our revolving bank credit facility.
During the first quarter of 2012, our realized oil sales price (unhedged) increased 12.8%, compared to the first quarter of 2011. Two comparable benchmarks are the unweighted average daily posted spot price of West Texas Intermediate (“WTI”) crude oil, which increased 9.5% from the comparable period, and the unweighted average daily posted spot price of Brent crude oil, which increased 12.6 % from the comparable period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore production, which is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the first quarter of 2012, these various crudes sold at a significant premium relative to WTI. During the first quarter of 2012, premiums for Heavy Louisiana Sweet crude ranged between $11.00 and $19.00 per barrel and premiums for Light Louisiana Sweet crude ranged between $10.00 and $17.00 per barrel. In comparison, the average premium spread for these crudes was approximately $2.00 to $3.00 per barrel during 2010, which is representative of the historical norm. We may continue to experience higher premiums to WTI crude in our future sales of crude oil until such time as the causative factors are resolved. We cannot predict with any certainty how long such pricing conditions will last.
A possible cause cited by industry publications for the premiums afforded our offshore crudes is an over supply situation at Cushing, Oklahoma. Due in part to the over supply situation, the owners of the Seaway pipeline announced plans to reverse the flow of crude oil and, starting on June 1, 2012, will transport crude oil from the Midwest to the Gulf coast at a rate of 150,000 barrels per day. The announcement also stated the volumes are fully nominated and that it plans to expand volumes to 400,000 barrels per day, subject to volume commitments and other conditions. This will affect the over supply situation at Cushing and may affect the premiums we receive on our offshore oil production. An additional factor that has affected the premiums for Heavy Louisiana Sweet and Light Louisiana Sweet is the difference between the Brent and WTI crude oil benchmarks, which continue to have a higher spread than historical norms. When Brent increases versus WTI, it boosts the value of low-sulfur U.S. grades that compete with West Africa oil priced against the European Benchmark. This trend of Brent spreads being higher began in the first quarter of 2011 and has continued through the first quarter of 2012.
Oil prices are affected by world events such as production stoppages in the Middle East and demand changes in Europe. If world economic growth continues, which is currently being driven by China, Brazil, India and Russia. Many commentors believe such activity will support strong crude oil prices.
According to industry sources, NGLs production hit another record in the month of January (2.4 million barrels per day and the last real bench mark that we have) representing an 18% increase year over year. During the first quarter, ethane prices weakened while the remainder of the NGLs stream remained firm. As long as the crude to natural gas ratio remains wide, NGLs production should continue to be high, which may put downward pressure on ethane pricing and in turn weaken the entire NGLs stream.
Natural gas prices are much more affected by domestic issues, such as weather (particularly extreme heat and cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the first quarter of 2012, our average realized sales price of natural gas (unhedged) decreased 37.8% from the first quarter of 2011 to $2.67 per Mcf. A comparable bench mark is the Henry Hub unweighted average daily posted spot price, which decreased 41.6% from the comparable period. We expect continued weakness in natural gas prices as producers continue to drill to hold leases, natural gas storage levels continue to build to ever higher levels throughout this injection season, natural gas continues to be produced as a by-product in conjunction with the substantial ramp up of oil drilling, liquefied natural gas availability is increasing and production efficiency gains are achieved in the shale gas areas resulting from better fracking techniques. According to industry and government data, U.S. natural gas production has increased approximately 9% for the three month period ended January 2012 (latest data available) versus the comparable prior year period in spite of an approximate 30% decline in the number of drilling rigs exploring for natural gas (April 2012 compared to April 2011). Industry newsletters indicate that storage may reach maximum capacity in the fall of 2012, which could negatively affect natural gas prices. Due to elevated oil prices, drilling activity for oil in the U.S. is at high levels and successful oil wells are producing natural gas as a by-product, which has increased natural gas production. According to industry sources, the total U.S. oil rig count is up over 50% in March 2012 compared to March 2011. Factors that could lead to higher natural gas prices include an increase in demand from economic growth, conversions to natural gas from other energy sources or production shut-ins due to economic factors.
Should prices decline for oil and natural gas in the future, it would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those were to occur and were significant, it may limit the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry.
There continues to be many proposed changes in laws, regulations, guidance and policy in our industry. The process for obtaining offshore drilling permits, especially deep water drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in the last two years are regulations related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time.
Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011
Revenues . Total revenues increased $25.0 million to $235.9 million for the first quarter of 2012 as compared to the same period in 2011. Oil revenues increased $28.4 million, NGLs revenues increased $8.4 million, natural gas revenues decreased $12.5 million and other revenues increased $0.7 million. The oil revenue increase was attributable to a 12.8% increase in the average realized sales price (unhedged) to $110.39 per barrel for first quarter of 2012 from $97.90 per barrel for the first quarter of the prior year, combined with a 6.5% increase in sales volumes. The NGLs revenue increase was attributable to an increase of 52.0% in sales volumes from the comparable period, and was partially offset by a 3.3% decrease in the average realized sales price (unhedged) to $48.51 per barrel for the first quarter of 2012 from $50.14 per barrel for the prior year period. The sales volume increase for oil and NGLs is primarily attributable to increases associated with the properties acquired in 2011. The decrease in natural gas revenue resulted from a 37.8% decrease in the average realized natural gas sales price (unhedged) to $2.67 per Mcf in the first quarter of 2012 from $4.29 per Mcf for the prior year period, partially offset by a 21.0% increase in sales volumes. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Revenues from oil and liquids increased as a percent of our total revenues, increasing to 83.2% for the first quarter of 2012 compared to 75.6% for the prior year period. NGLs realized prices as a percent of oil realized prices decreased to 43.9% for the first quarter of 2012 compared to 51.2% for the prior year period.
Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $4.3 million to $56.7 million in the first quarter of 2012 compared to the prior year period. On a per Mcfe basis, lease operating expenses decreased to $2.11 per Mcfe during the first quarter 2012 compared to $2.31 per Mcfe during the comparable 2011 period. On a component basis, base lease operating expenses and insurance premiums increased $6.8 million and $1.9 million, respectively. As a partial offset, facilities expense and hurricane remediation costs net of insurance claims, decreased $3.3 million and $1.1 million, respectively. Workover expenses were approximately flat between periods. The increase in base lease operating expenses is primarily attributable to the properties purchased in 2011. The increase in insurance premiums is attributable to increases effective with the June 1, 2011 renewal, which included a substantial improvement in coverage. The decrease in facilities expense is primarily attributable to pipeline repairs at our Ship Shoal 300 field and work on newly acquired deepwater properties, which were completed in the 2011 period that did not reoccur in the comparable period in 2012. Workover costs were flat as the workover costs incurred for our onshore operations were offset by a decrease in our offshore activities. Hurricane remediation costs net of insurance claims decreased as there were minimal net costs in the first quarter of 2012 compared to net costs incurred in the prior year period related to returns of previously received insurance reimbursements.
Production taxes. Production taxes increased to $1.5 million during 2012 compared to $0.3 million in 2011 primarily due to the properties acquired in 2011 and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.
Gathering and transportation costs. Gathering and transportation costs decreased $0.3 million for the first quarter compared to the prior year period.
Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, including accretion for ARO, increased to $3.29 per Mcfe for the first quarter of 2012 from $3.26 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $88.5 million for the first quarter of 2012 from $74.1 million in the prior year period. DD&A on a per Mcfe basis increased slightly for the first quarter while DD&A on a nominal basis increased primarily due to higher production volumes.
General and administrative expenses (“G&A”). G&A increased to $29.5 million for the first quarter of 2012 from $18.1 million for the prior year period, primarily due to an $8.3 million litigation accrual and premiums related to surety bonds. G&A on a per Mcfe basis was $1.10 per Mcfe for the first quarter of 2012, compared to $0.80 per Mcfe for the prior year period.
Derivative loss. For the first quarter of 2012 and 2011, our derivative losses were $39.6 million and $23.8 million, respectively, and relate to the change in the fair value of our crude oil commodity derivatives as a result of increases in crude oil prices relative to the contract prices. Although the contracts relate to production for the current and future years, changes in the fair value for all open contracts are recorded currently. For the first quarter of 2012, $5.8 million of the loss was realized and $33.8 million was unrealized. For the first quarter of 2011, $2.2 million of the loss was realized and $21.6 million was unrealized. For additional information about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instruments .
Interest expense . Interest expense incurred increased to $13.9 million for the first quarter of 2012 from $10.1 million for the prior year period. The amount of our Senior Notes outstanding increased to $600.0 million from $450.0 million due to issuing our 8.50% Senior Notes and repurchasing our 8.25% Senior Notes, which occurred during June and July of 2011. During the first quarter of 2012 and 2011, $3.2 million and $1.4 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties. The increase is primarily attributable to unevaluated properties acquired in conjunction with the acquisition of the Yellow Rose Properties.
Income tax expense. Income tax expense decreased to $2.0 million for the first quarter of 2012 compared to $10.2 million for the same period of 2011. The decrease is primarily attributable to the change in pre-tax income. Our effective tax rate for the three months ended March 31, 2012 was 38.1% and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to prior years. Our effective tax rate for the three months ended March 31, 2011 was 35.3%, which approximated the federal statutory rate.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments and pay dividends. We have funded such activities with cash on hand, cash provided by operating activities, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.
Cash flow and working capital. Net cash provided by operating activities for the first quarter of 2012 was $128.2 million, compared to $72.7 million for the first quarter of 2011. The change was primarily due to higher revenues associated with increases in prices for oil and NGLs and increased production volumes, decreased ARO payments, and lower income tax payments, partially offset by lower natural gas prices. Our combined production of oil, NGLs and natural gas on a Mcfe basis during the first quarter of 2012 was 18.4% higher than the first quarter of 2011, but our combined average realized sales price (hedged) per Mcfe was 7.1% lower than the comparable 2011 period.
Net cash used in investing activities during the first quarter of 2012 and 2011 was $85.1 million and $40.0 million, respectively, which represents our investments in both offshore and onshore oil and gas properties. The increase is primarily attributable to the increase in wells drilled in our onshore properties. There were no acquisitions completed in either period.
Net cash used in financing activities was $39.0 million and $3.0 million during the first quarter of 2012 and 2011, respectively. The cash used in the first quarter of 2012 was attributable to net pay downs on the revolving bank credit facility and dividend payments. The cash used in the first quarter of 2011 was attributable to dividend payments.
At March 31, 2012, we had a cash balance of $8.5 million and $490.3 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $575.0 million as of March 31, 2012.
Credit agreement and long-term debt. At March 31, 2012 and December 31, 2011, $84.0 million and $117.0 million, respectively, were outstanding under our revolving bank credit facility. During the three months ended March 31, 2012, the outstanding borrowings on our revolving bank credit facility ranged from $64.0 million to $145.0 million. At March 31, 2012 and December 31, 2011, $600.0 million of our 8.50% Senior Notes was outstanding. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements, but additional financing could be required if we are successful in finding suitable acquisitions. For additional information about our long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.
Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. On May 7, 2012, we executed an amendment to the credit agreement, which, among other things, increased the number of banks, increased the borrowing base to $650.0 million and added a survivorship of security provision. For additional information, refer to Financial Statements – Note 13 – Subsequent Event under Part I, Item 1 of this Form 10-Q. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement and all applicable covenants related to the 8.50% Senior Notes as of March 31, 2012.
CONF CALL
Manny Mondragon
Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the first quarter 2009 results. Before I turn the call over, I have a few items to go over.
If you'd like to be on the company's e-mail distribution list to receive future newscasts or you experiencing technical difficulty and didn't receive yours, please call DRG&E's office at 713-529-6600 and someone will be glad to help you. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the company's website at www.wtoffshore.com or via recorded replay until May 12, 2009. To use the replay feature call 303-590-3030 and dial the passcode 4065057.
Information recorded on this call speaks only as of today, May 5, 2009 and therefore time sensitive information may no longer be accurate as of the date of any replay. Today, management is going to discuss certain topics that contain forward-looking information, which is based on management's beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected production expenses for 2009.
Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties and assumptions including among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production, operations and estimated reserves, unexpected future capital expenditures, competition, the risks, the success of risk management activities, governmental regulations and other factors described in the company's most recent annual report on Form 10-K and subsequent filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially from those expected.
Please also note that this conference call contains references to non-GAAP financial measures. You can find reconciliations of those non-GAAP financial measures to GAAP financial measures in the Form 8-K filed by the company earlier today as well as in this morning's press release.
Now, I'd like to turn the call to Mr. Tracy Krohn.
Tracy Krohn
Thanks, Manny, and good morning, everyone. Thanks for joining us for our first quarter 2009 conference call. This morning we are going to review significant events that took place in the first quarter 2009 and will provide an update on how the company is looking for the rest of the year.
With me today here are Danny Gibbons, our CFO, Steve Schroeder, our COO, and Jamie Vazquez, our President.
Drilling and CapEx, let's talk a little bit about that. We continue to experience success with the drill bit, in the first quarter we drilled three out of four successful conventional shelf wells. Since the end of the quarter, we successfully drilled two additional wells and one non-commercial well. Steve is going to give you details behind that activity, but needless to say we are still actively drilling.
As we mentioned in our last call, our 2009 drilling program is front-end loaded. During the first quarter, we spent about half of our current capital budget, which is between $220 million and $270 million for the year, our activity level will start to slowdown towards the end of the second quarter, as we complete our current drilling programs at Main Pass, South Marsh Island and Ship Shoal 349 Mahogany and complete most of the work on the Daniel Boone project.
In the second half of the year, we'll be spending budgeted dollars on development projects like Daniel Boone, our recently successful wells. Otherwise, we'd prefer to remain flexible, build cash, and maintain the ability to pursue other strategic options, such as drilling opportunities, corporate acquisitions or asset purchases.
We believe we'll be able to find our CapEx program from internally generated cash flow, cash on hand, and/or borrowings from our revolving credit facility.
Let's talk a little bit about our credit facility and liquidity. We just completed the semi-annual redetermination of our borrowing base, which is now set at $405 million. In connection with the borrowing base redetermination, we amended the Credit Agreement, which will greatly enhance our financial flexibility.
As part of that redetermination process, we also paid-off our Term Loan B with a draw under the revolving portion of our Credit Agreement, which results in a remaining revolver availability of $200 million. So we have that $200 million available from the banks, and $227 million cash on the balance sheet as of April 30th.
By paying off the Term Loan B vis-Ă -vis our revolving credit facility, which had a maturity of August 2010 with the revolver, we extended maturity from August 2010 to 2012. That improves our current ratio and helps create more overall liquidity. Now that the redetermination is complete, our liquidity position is established and we can move forward on strategic opportunities.
In March, we announced the $25 million stock repurchase program during the quarter ended March 31. We purchased 1.4 million shares of our common stock for approximately $9.2 million at an average price of $6.47 per share in the open market in accordance with the repurchase program. The primary purpose of the program was more administratively driven than strategic.
When the stock price dropped, we realized that we didn't have enough share to completely fund our employee incentive plan for bonus awards related to the 2008 planed year. The lower price meant significantly new more shares were needed than were available to be issued. The Board determined the company should purchase shares in the open market rather than further dilute shareholders by issuing new shares.
For further details, I'll refer you to our recently filed proxy for a more complete description of the situation, and the planned description, but suffice to say that so far that's proven to be the right answer to that issue of stock price dropping while we were getting ready to issue shares to employees.
Now here is Danny Gibbons to expand further on the financials.
Danny Gibbons
Thanks, Tracy and good morning everyone. We put out an earnings release this morning that covers numerous financial items, so I will refer you to that release and not cover those items again.
What I would like to discuss is our cash balance and liquidity and federal income tax position. Our cash balance at March 31, 2009 was $251 million, compared to $357.6 million at the end of 2008.
Cash balances declined during the quarter as we spent $128.4 million on capital expenditures, $9.2 million to repurchase shares of our common stock, $4.6 million for interest and dividend payments, and $40.1 million in accounts payable reductions and other working capital changes.
In addition, EBITDA was $57.2 million, and was impacted by reduced commodity prices without a proportionate decrease in operating cost and reduced production volumes that were affected by hurricane damage to third party pipelines.
Cash balances benefited at the end of the quarter as we received a $17.7 million federal income tax refund. As we discussed at recent conferences, our capital expenditure budget is front end loaded, so we expected that cash balances would decline through the first half of the year, and then rebuild later in the second half of the year. We still believe that will be the case.
Also, as Tracy had just mentioned, we have amended our Credit Agreement. What we did was we changed our maximum leverage ratio which is the ratio of total debt to EBITDA, as those terms are defined in the Credit Agreement.
The amended ratio is 3.75:1 for the four quarters ended September 30, 2009, 3.5:1 for the four quarters ended December 31, 2009, 3.25:1 for the four quarters ended March 31, 2010 and 3:1 thereafter. Now with the borrowing base redetermination complete, and the completed amendment, we have great financial flexibility.
Let me move on to federal income taxes. We recorded an income tax benefit of $24 million in the first quarter of 2009. This resulted from a pre-tax loss of $255 million, but only a portion of which is expected to be available to be carried back to 2007, which is the only open tax year that is currently available.
Our annualized effective tax rate for the quarter ended March 31, 2009, was approximately 9.4%, and is primarily the result of the effective evaluation allowance attributable to our deferred tax assets.
With that, I'll turn it over to Steve Schroeder. Steve?
Steve Schroeder
Thanks, Danny. Let me start with an update on our drilling program. We currently have three rigs working, of which, all are operated; and this morning we began demobilizing the Rowan Gorilla IV. We also have one non-operated rig conducting a multi-well recomplete program.
While our only first quarter development well was unsuccessful, all three of our exploration wells were successful including the South Timbalier 320 A-7, South Marsh Island 39 C-4 and the Main Pass 283 A-3 side track.
Each of these wells were drilled from existing infrastructure, and have now been completed, and are currently online producing at a combined net rate of 2300 barrels of oil per day, and 3.6 million cubic feet per day or 17.4 million cubic feet equivalent per day net to W&T.
Of these three wells, the 65 feet of oil discovered in the Main Pass 283 A-3 side track is the most significant. This well's success confirmed the geologic model that identified several future exploration drilling locations along the same channel system.
These drilling offsets are currently planned for future drilling program, pending the long-term production results of the A-3 side track. The Main Pass 283 field also provided a second success during the second quarter, the Main Pass 279 A-5 sidetrack. This high yield gas condensate well is currently being completed with first production anticipated shortly.
Also in the second quarter, we completed the Mahogany A-12 sidetrack development well in Ship Shoal 349 field. This well drilled through the yields main oil reservoir at a structurally highest point, encountering 80 net feet of oil, sand full to base. This zone was caged-off, and we attempted to drill deeper toward additional exploratory zones.
Unfortunately, we experienced an underground blowout, and decided not to risk the completion in the fields main pay zone, and suspended drilling deeper. First production from this well is expected later this week, once the rig is a safe distance away from the platform after demobilizing.
Additionally, work continues on our future drilling program which includes a deep shelf well designed to explore Mahogany deep geological structure. The proposed well targets upper and middle Miocene age sediments to a much deeper depth of about 25,000 feet.
Difficulties were encountered by the operator of the South Marsh Island 39 B-2 side track exploration well. This is the second well of the program following the successful C-4 well earlier this year. The well has been temporarily suspended with future drilling plans contingent on developing a revised drilling plan.
Our last active platform drilling program is at South Timbalier 314 field, where we just finished drilling the non-commercial A-4 well. This well has been plugged and abandoned. Current plans call for drilling one to two additional wells in this field.
Now, to give you an update as to the progress of the Daniel Boone development project. The flow line welding is complete and Technip's Deep Blue, which is an ultra deepwater pipe lay vessel is scheduled to start mobilization this month. The pipe will be spooled and ready for installation by mid-May.
The flowline and umbilical right-of-way permits have received regulatory approval. We are encouraged with the progress made to-date, and still see this project as on schedule and on budget. We anticipate first production of oil in late third quarter of 2009.
We currently are producing about 260 million cubic feet equivalent per day. We have three wells that were completed in the first quarter, and now we're producing 17.4 million cubic feet equivalent per day.
We currently have about 26 million cubic feet equivalent per day net, shut-in from hurricane damage platforms, and shut-in third party pipelines. The majority of the production will be back online in the third and fourth quarter of this year, and has been incorporated into our guidance.
For the second quarter 2009, the company anticipates production to be between 1.6 million and 2.0 million barrels of oil, and 11.4 billion and 13.9 billion cubic feet of natural gas, or a total of between 21.1 billion and 25.8 billion cubic feet of gas equivalent. The midpoint for this quarter is 10% higher than first quarter's production. For a full year 2009, we've not changed our production guidance.
Moving on to lease operating expenses. Lease operating expenses for the first quarter of 2009 was $45.1 million, excluding hurricane repair cost, base LOE for the first quarter was $40 million, which is below the low-end of guidance. The largest driver for the difference was in workover and facility expenses, which were about $5.3 million under forecast.
There were no large workover projects operated or non-operated during the first quarter. In fact, we were able to eliminate the need for an $800,000 workover, with a much smaller $40,000 repair at our Main Pass 108 field. Facility expenses were also less than forecast. This is mainly due to the concentration of work done in hurricane remediation.
We mentioned something here about our approach to operating costs in general. We have launched a profitability initiative throughout the company, which emphasizes facility optimization, well performance reviews, wellbore utilization analysis, and reduction of cost.
On the cost cutting front, the effort is to trim as much cost as possible in this challenging commodity price environment. Please do not take this to mean that we are not performing the necessary repairs and maintenance to continue operations safely because we wouldn't compromise the integrity of our operations; however, to date, we have reduced the number of helicopters, boats and manpower.
In addition to the fewer boats and helicopters, we will benefit from lower fuel consumption and prices. We have benefited from this initiative and will continue to benefit throughout the rest of the year.
Looking to the second quarter of 2009, lease operating expenses are expected to be between $50 million and $63 million. This does not include allowance for hurricane related expenses. This is also a slight increase from the first quarter due to the normal increase in activity during the spring and summer months.
As weather improves, we ramp up our blast and paint, repairs and maintenance activity. For the year, we are forecasting lower base LOE and therefore lowering guidance to reflect what we believe are lower costs such as transportation, fuel, labor, and general overheads.
Gathering, transportation and production taxes for the first quarter were $3.3 million, which were below the low-end of guidance. This is mainly due to lower than anticipated sales in fields producing from within state waters and lower processing volumes.
Gathering, transportation and production taxes for the second quarter are expected to be between $5 million and $6 million and unchanged for the year.
Now, let me turn it back to Tracy for closing remarks. Tracy?
Tracy Krohn
Thanks, Steve. I'd like to talk a little bit about how we're currently looking at our opportunities and our use of liquidity. As you all know or should surmise, it's becoming a buyers' market and companies with good liquidity have a distinct advantage.
We don't have a crystal ball, and we don't know where commodity prices are going in the near-term or whether the capital markets will be open in 2009 or later, so while we're actively looking at opportunities, we're going to be patient, we're going to focus on paying the right price, spend conservatively and efficiently.
We continue to evaluate opportunities in various areas outside the Gulf of Mexico. That includes domestic onshore and international areas. We don't want to rush in, pay too much or pursue something that doesn't fit our objectives.
As I've said before, our ultimate criteria is does it make money? Philosophically, I don't have anything against those other areas; just the Gulf of Mexico has always provided us with the highest rates of return.
We do have two major criteria for international opportunities. First one is their rule of law. Don't really like getting shot at. Second, we need to feel secure that we'll get paid and that we'll get paid on a regular basis.
For those of you who aren't aware of it we have a very well staffed A&D team. The team includes two fully dedicated geologists, four reservoir engineers and two technical staff members. In addition, our Executive Vice President and Manager of Corporate Development Reid Lea is also a reservoir engineer.
We believe we're properly staffed to handle most of the opportunities presented to our team at any given time and I expect this to be a very busy year for them.
One of the good things about this current economic atmosphere is that our banks have made a very positive statement with regard to our borrowing base. We do have liquidity. We have cash, and we have functional options about how we want to proceed in this environment.
In 1986, we had about a $1 million in liquidity. We built a company on that. Today, we have hundreds of times more liquidity and I have to believe we'll do better this time around.
With that, that concludes our prepared remarks and we're ready to take your questions. Operator, would you please open the phone lines for Q&A?
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Fund Letters
