We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located in the Antrim Shale in Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida, the New Albany Shale in Indiana and Kentucky, and the Permian Basin in West Texas.
Our assets are characterized by stable, long-lived production and reserve life indexes averaging greater than 16 years. Our fields generally have long production histories, with some fields producing for over 100 years. We have high net revenue interests in our properties.
We are a Delaware limited partnership formed on March 23, 2006. Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006, and our wholly owned subsidiary since June 17, 2008. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BOLP and BOLP’s general partner BOGP. We own all of the ownership interests in BOLP and BOGP.
Our wholly owned subsidiary, BreitBurn Management, manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 7 to the consolidated financial statements in this report for information regarding our relationship with BreitBurn Management.
In connection with our initial public offering in October 2006, BEC contributed to us certain properties, which include fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming. In 2007, we acquired the Lazy JL Field in Texas, five fields in Florida’s Sunniland Trend, a limited partnership interest in a partnership that owns the East Coyote and Sawtelle fields in the Los Angeles Basin in California, and natural gas, oil and midstream assets in Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan and New Albany Shale in Indiana and Kentucky, transmission and gathering pipelines, three gas processing plants and four NGL recovery plants.
As of December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of which approximately 75 percent were natural gas and 25 percent were crude oil. Of our total estimated proved reserves, 78 percent were located in Michigan, 12 percent in California and 6 percent in Wyoming, with the remaining 4 percent in Florida, Texas, Indiana and Kentucky. As of December 31, 2008, the total standardized measure of discounted future net cash flows was $592 million.
Our internet website address is www.breitburn.com. We make available, free of charge at the “Investor Relations” portion of our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Acts of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The information contained on our website does not constitute part of this report.
Long Term Business Strategy
Our goal is to provide stability and growth in cash distributions to our unitholders. In order to meet this objective, we plan to continue to follow our core investment strategy, which includes the following principles:
Acquire long-lived assets with low-risk exploitation and development opportunities;
Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery; Reduce cash flow volatility through commodity price derivatives; and Maximize asset value and cash flow stability through our operating and technical expertise.
2009 Operating Focus
We completed a series of significant oil and gas acquisitions during 2007. During 2008, our principal operating focus was the development and integration of those acquired assets. In light of the current market environment for oil and natural gas prices and the state of the financial and capital markets, we expect 2009 to be a year of increased internal focus and decreased acquisition activity. However, as the commodity and financial markets eventually stabilize, we intend to increase our focus on acquisition opportunities consistent with our core long-term strategy.
Our goals in 2009 are to fund our operations, capital expenditures, interest payments and distributions to unitholders from our internally generated cash flow and to preserve financial flexibility and liquidity to maintain our assets and operations in anticipation of future improvement in the overall economic environment, commodity prices and the financial markets.
In response to the rapid and substantial decline in oil and natural gas prices, the outlook for the broader economy and the ongoing turmoil in the financial markets, and consistent with our goals for 2009, we have elected to significantly reduce our capital expenditures and drilling activity in 2009. Our capital program is expected to be approximately $20 million in 2009, compared to approximately $129 million in 2008.
Because of the reduced capital program in 2009 and the natural decline in our production rates, we expect to produce less oil and natural gas in 2009 than we did in 2008. If oil and natural gas prices improve, or if operating and development costs decline, and we elect to increase the scope of our capital program based on these or other factors, we would expect an increase in our anticipated 2009 production rate and aggregate volumes.
In light of the market environment and our reduced capital program, we are focused on substantially reducing operating and general and administrative costs in 2009. Our focus on reducing costs has included, but is not limited to, a realignment of certain divisional operating roles to consolidate responsibilities, negotiated reductions in fees and expenses from third party service providers, as well as planned personnel reductions in both operations and administrative functions.
Hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices. As of February 27, 2009, we have hedged (including physical hedges) approximately 84 percent of our 2009 expected production. In 2009, we have 47,542 MMBtu/d of natural gas and 5,778 Bbls/d of oil hedged at average prices of approximately $8.17 and $73.12, respectively. In 2010, we have 47,275 MMBtu/d of natural gas and 6,080 Bbls/d of oil hedged at average prices of approximately $8.26 and $82.52, respectively. In 2011, we have 41,971 MMBtu/d of natural gas and 5,603 Bbls/d of oil hedged at average prices of approximately $8.62 and $77.60, respectively. In 2012, we have 38,257 MMBtu/d of natural gas and 5,016 Bbls/d of oil hedged at average prices of approximately $8.93and $91.95, respectively.
In 2006, we completed our initial public offering of 6,000,000 common units representing limited partner interests in us (“Common Units”) and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount. In connection with our initial public offering, BEC, our Predecessor, contributed to us certain fields in the Los Angeles Basin in California, including its interests in the Santa Fe Springs, Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn Basins in central Wyoming.
On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility.
On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were partially used to acquire a 99 percent limited partner interest in BEPI from TIFD and to terminate existing hedges related to future production from BEPI.
On November 1, 2007, we sold 16,666,667 Common Units in a third private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for the acquisition of certain assets and equity interests in certain entities from Quicksilver (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition.
On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding.
On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”). See Note 4 to the consolidated financial statements in this report for the purchase price allocation for this transaction. Also on June 17, 2008, we entered into a contribution agreement (the “Contribution Agreement”) with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.
On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into the First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.
On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects.
BreitBurn Corporation is owned by Messrs. Breitenbach and Washburn, the Co-CEOs of our general partner.
On February 19, 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan, increasing our outstanding Common Units to 52,770,011. On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights Agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.
The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading of the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.
The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.
As of December 31, 2008, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the outstanding Common Units. BEC owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.
Our Predecessor BEC, was a 96.02 percent owned indirect subsidiary of Provident until August 26, 2008, when members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.
In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five-year Administrative Services Agreement to manage BEC's properties. In addition, we entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.
BreitBurn Management manages all of our properties. BreitBurn Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel. On a net production basis, we operate approximately 82 percent of our production. As operator, we design and manage the development of wells and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oilfield services equipment used for drilling or maintaining wells on properties we operate. Independent contractors engaged by us provide all the equipment and personnel associated with these activities.
In October 2006, certain properties, which include fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming, were contributed to us by our Predecessor. In 2007, we acquired the Lazy JL Field in Texas, five fields in Florida’s Sunniland Trend, a limited partnership interest in a partnership that owns the East Coyote and Sawtelle fields in the Los Angeles Basin in California, and natural gas, oil and midstream assets in Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan and New Albany Shale in Indiana and Kentucky, transmission and gathering pipelines, three gas processing plants and four NGL recovery plants.
As of December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of which approximately 75 percent were natural gas and 25 percent were crude oil. As of December 31, 2007, our total estimated proved reserves were 142.2 MMBoe, of which approximately 59 percent were natural gas and 41 percent were crude oil. The decrease in reserves was primarily due to lower commodity prices at the end of 2008 ($45 per Bbl for oil and $5.62 per Mcf for natural gas) compared to prices at the end of 2007 ($96 per Bbl for oil and $7.48 per Mcf for natural gas). During 2008, we added proved reserves totalling 8.2 MMBoe from additions. This equates to 121 percent of our production for 2008. The reserve additions were offset by negative economic and technical revisions of 40.5 MMBoe.
Of our total estimated proved reserves as of December 31, 2008, 78 percent were located in Michigan, 12 percent in California and 6 percent in Wyoming, with the remaining 4 percent in Florida, Texas, Indiana and Kentucky. As of December 31, 2008, the total standardized measure of discounted future net cash flows was $592 million. During 2008, we filed estimates of oil and gas reserves as of December 31, 2007 with the U.S. Department of Energy, which were consistent with the reserve data reported for the year ended December 31, 2007 in Note 22 to the consolidated financial statements in this report.
Our estimated proved reserves were determined using $5.71 per MMBtu for gas and $44.60 per Bbl of oil for Michigan and California and $20.12 per Bbl of oil for Wyoming. For additional estimated proved reserves details, see Note 22 to the consolidated financial statements in this report.
Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as change in product prices or development and production expenses, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. See Part I—Item 1A “—Risk Factors” in this report, for a description of some of the risks and uncertainties associated with our business and reserves.
The information in this report relating to our estimated oil and gas proved reserves is based upon reserve reports prepared as of December 31, 2008. Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The reserve estimates are reviewed and approved by senior engineering staff and management. The process performed by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.
As of December 31, 2008, our Michigan operations comprised approximately 78 percent of our total estimated proved reserves. For the year ended December 31, 2008, our average production was approximately 10.7 MBoe/d or 64 MMcfe/d. Estimated proved reserves attributable to our Michigan properties as of December 21, 2008 were 80.9 MMBoe. Our integrated midstream assets enhance the value of our Michigan properties as gas is sold at MichCon prices, and we have no significant reliance on third party transportation. We have interests in 3,341 productive wells in Michigan.
During August of 2008, we reached a peak of 6 drilling rigs running in Michigan. We drilled a total of 116 wells in 2008 and had 106 approved drilling permits and 13 change of well status approvals for the Antrim re-entry program as of December 31, 2008. In addition to drilling, capital was spent to complete ten line twining projects and over 55 compression units were employed. These projects targeted casing pressure reduction in the pressure sensitive Antrim Shale. Line twining converts a single line gathering system, where natural gas and water are transported from the well to the central processing facility in one line, to a dual line system where the water and gas each have their own line to the central processing facility. As a result, the casing pressure at the well can be lowered thus increasing production. Our capital spending in Michigan for the year ended December 31, 2008 was $81 million. As of December 31, 2008
Proved Reserves Antrim Shale
The Antrim Shale underlies a large percentage of our Michigan acreage; wells tend to produce relatively predictable amounts of natural gas in this reservoir. Over 9,000 wells have been drilled by various companies with greater than 95 percent drilling success over its history. On average, Antrim Shale wells have a proved reserve life of more than 20 years. Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs through a sizeable well-engineered drilling program are the keys to profitable Antrim development. Significant growth opportunities include infill drilling and recompletions, horizontal drilling and bolt-on acquisitions. Our estimated proved reserves attributable to our Antrim Shale interests as of December 31, 2008 were 72.1 MMBoe or 433 Bcfe, of which 93 percent was proved developed.
In 2008, we drilled 90 productive development wells in the Antrim Shale, employing a combination of vertical, high angle directional, horizontal and re-entry horizontal techniques. We drilled no dry wells in the Antrim Shale in 2008.
Our non-Antrim interests are located in several reservoirs including the Prairie du Chien (“PRDC”), Richfield (“RCFD”), Detroit River Zone III (“DRRV”) and Niagaran (“NGRN”) pinnacle reefs. Our estimated proved reserves attributable to our non-Antrim interests as of December 31, 2008 were 8.8 MMBoe or 52.6 Bcfe.
The PRDC will produce dry gas, gas and condensate or oil with associated gas, depending upon the area and the particular zone. Our PRDC production is well established, and there are numerous proved non-producing zones in existing well bores that provide recompletion opportunities, allowing us to maintain or, in some cases, increase production from our PRDC wells as currently producing reservoirs deplete.
The vast majority of our RCFD/DRRV wells are located in Kalkaska and Crawford counties in the Garfield and Beaver Creek fields. Potential exploitation of the Garfield RCFD/DRRV reservoirs either by secondary waterflood and/or improved oil recovery with CO2 injection is under evaluation; however, because this concept has not been proved, there are no recorded reserves related to these techniques. Production from the Beaver Creek RCFD/DRRV reservoirs consists of oil with associated natural gas. In the fall of 2008, we received permission from the Michigan Department of Environmental Quality to co-mingle the RCFD and DRRV formations in the Garfield project. This co-mingling will enable us to add the DRRV formation to existing and future RCFD wells at minimal cost as opposed to drilling a separate well for the DRRV.
Our NGRN wells produce from numerous Silurian-age Niagaran pinnacle reefs located in the northern part of the lower peninsula of Michigan. Depending upon the location of the specific reef in the pinnacle reef belt of the northern shelf area, the NGRN pinnacle reefs will produce dry natural gas, natural gas and condensate or oil with associated natural gas.
In 2008, we drilled 25 productive development wells and one salt-water disposal well in the non-Antrim fields. Of the 25 development wells, three were in PRDC, 14 were in RCFD and eight were in DRRV. We drilled one dry development well in the non-Antrim fields in 2008.
Los Angeles Basin, California
Our operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin. For the year ended December 31, 2008, our California average production was approximately 3.2 MBoe/d. Estimated proved reserves attributable to our California properties as of December 31, 2008 were 12.4 MMBoe. Our four largest fields, Santa Fe Springs, East Coyote, Rosecrans and Sawtelle, made up 89 percent of our production in 2008 and 87 percent of our estimated proved reserves in California as of December 31, 2008. In 2008, we drilled four productive development wells and no dry development wells in California. Our capital spending in California for the year ended December 31, 2008 was $20 million.
Santa Fe Springs Field – Our largest property in the Los Angeles Basin, measured by estimated proved reserves, is the Santa Fe Springs Field. We operate 161 active wells in the Santa Fe Springs Field and own a 99.5 percent working interest. Santa Fe Springs has produced to date from up to 10 productive sands ranging in depth from 3,000 feet to more than 9,000 feet. The five largest producing zones are the Bell, Meyer, O'Connell, Clark and Hathaway. In 2008, our average production from the Santa Fe Springs Field was approximately 1.6 MBoe/d and our estimated proved reserves as of December 31, 2008 were 4.8 MMBoe, of which 93 percent was proved developed.
East Coyote Field – Our interest in this field was acquired on May 25, 2007. BEC operates 69 active wells in the East Coyote Field. We own a 95 percent working interest. The East Coyote Field has producing zones ranging in depth from 2,500 feet to 4,000 feet. Our average production from the East Coyote Field for the year ended December 31, 2008 was approximately 532 Boe/d and our estimated proved reserves as of December 31, 2008 were 3.3 MMBoe.
Sawtelle Field – Our interest in this field was acquired on May 25, 2007. BEC operates 14 active wells in the Sawtelle Field. We own a 93 percent working interest. The Sawtelle Field has produced from several productive sands ranging in depth from 9,000 feet to 10,500 feet. Our average production from the Sawtelle Field was approximately 343 Boe/d and our estimated proved reserves as of December 31, 2008 were 1.6 MMBoe.
Rosecrans Field – We operate 46 active wells in the Rosecrans Field and own a 100 percent working interest. The Rosecrans Field has produced from several productive sands ranging in depth from 4,000 feet to 8,000 feet. The producing zones are the Padelford, Maxwell, Hoge, Zins and the O’dea. In 2008, our average production from the Rosecrans Field was approximately 355 Boe/d and our estimated proved reserves as of December 31, 2008 were 1.1 MMBoe.
Other California Fields – Our other fields include the Brea Olinda field, which has 75 active wells producing approximately 207 net Boe/d on average in 2008 and estimated proved reserves as of December 31, 2008 of 0.8 MMBoe; the Alamitos lease of the Seal Beach Field, which has ten active wells producing approximately 93 net Boe/d on average in 2008 from the McGrath and Wasem formations at approximately 7,000 feet; and the Recreation Park lease of the Long Beach Field, which has seven active wells producing approximately 48 net Boe/d on average in 2008 from the same zones as the Alamitos lease, but approximately 1,000 feet deeper and estimated proved reserves as of December 31, 2008 of 0.8 MMBoe. We have a 100 percent working interest in Brea Olinda and Alamitos and a 60 percent working interest in Recreation Park.
Wyoming Wind River and Big Horn Basins, Wyoming
For the year ended December 31, 2008, our average production from our Wyoming fields was approximately 2.2 MBoe/d and estimated proved reserves at December 31, 2008 totaled 6.2 MMBoe. Four fields, Black Mountain, Gebo, North Sunshine and Hidden Dome, made up 83 percent of our 2008 production and 94 percent of our 2008 estimated proved reserves in Wyoming.
In 2008, we drilled six new productive development wells, three successful developmental deepenings of existing wells and one dry development well in Wyoming. The dry development well was drilled in the West Oregon Basin Field. A total of ten new wells and deepenings of existing wells were drilled in Wyoming during 2008. Additionally, a total of 19 workovers and recompletions, resulting in an incremental 680 Boe/d of production, were performed in Wyoming during 2008. Our capital spending in Wyoming for the year ended December 31, 2008 was $11 million.
Black Mountain Field – We operate 50 active wells in the Black Mountain Field and hold a 98 percent working interest. Production is from the Tensleep formation with producing zones as shallow as 2,500 feet and as deep as 3,900 feet. Our average production from the Black Mountain Field was approximately 471 Boe/d in 2008 and our estimated proved reserves as of December 31, 2008 were 3.3 MMBoe, of which 79 percent was proved developed.
Gebo Field – We operate 51 active wells in the Gebo Field and hold a 100 percent working interest. Production is from the Phosphoria and Tensleep formations with producing zones as shallow as 4,500 feet and as deep as 5,300 feet. In 2008, our average production from the Gebo Field was approximately 670 Boe/d and our estimated proved reserves as of December 31, 2008 were 1.0 MMBoe.
North Sunshine Field – We operate 32 active wells in the North Sunshine Field and hold a 100 percent working interest. Production is from the Phosphoria at 3,000 feet and the Tensleep at about 3,900 feet. In 2008, our average production from the North Sunshine Field was approximately 376 Boe/d and our estimated proved reserves as of December 31, 2008 were 0.6 MMBoe, of which 100 percent was proved developed. In 2008, we drilled three successful crude oil wells in this field.
Hidden Dome Field – We operate 25 active wells in the Hidden Dome Field and hold a 100 percent working interest. Production is from the Frontier, Tensleep and Darwin formations with the producing zones as shallow as 1,200 feet and as deep as 5,000 feet. In 2008, our average production from the Hidden Dome Field was approximately 297 Boe/d and our estimated proved reserves as of December 31, 2008 were 0.9 MMBoe.
Other Wyoming Fields – Our other fields include the Sheldon Dome Field and Rolff Lake Fields in Fremont County, where we operate 17 active oil wells and four active gas wells in the Frontier to the Tensleep formations at depths up to 7,300 feet. In 2008, our Sheldon Dome and Rolff Lake fields produced on average approximately 133 net Boe/d and 73 net Boe/d, respectively. We also operate six active wells in the Lost Dome Field in Natrona County (outside the Wind River and Big Horn Basin) producing from the Tensleep formation at approximately 5,000 feet. In 2008, our average production from the Lost Dome Field was approximately 60 Boe/d. The other two fields we operate are the West Oregon Basin and Half Moon Fields in Park County, with seven total wells with six active oil producing wells and one active natural gas producing well. In 2008, we produced on average approximately 99 net Boe/d between the two fields in Park County from the Frontier and Phosphoria formations at depths from 1,200 to 4,000 feet. Rolff Lake Fields and Lost Dome Field had estimated proved reserves as of December 31, 2008 of 0.3 MMBoe and 0.1 MMBoe, respectively. We hold a 90 percent working interest in the Sheldon Dome Field and 100 percent working interests in the Rolff Lake, West Oregon Basin and Half Moon fields.
Our five Florida fields were acquired in May 2007. We operate 18 active wells. Production is from the Cretaceous Sunniland Trend of the South Florida Basin at 11,500 feet. The South Florida Basin is one of the largest proven and sourced geological basins in the United States. The Sunniland Trend has produced in excess of 115 million barrels of oil from seven fields. Our fields are 100 percent oil and oil quality averaged 24 degrees API. As of December 31, 2008, we had estimated proved reserves of approximately 2.0 MMBbls and a reserve life index in excess of 15 years in these fields. In 2008, our average production from our Florida fields was approximately 1.6 MBbls/d. Production from the Raccoon Point field currently accounts for more than half of our Florida production. We hold a 100 percent working interest in our Florida fields.
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In 2008, no wells were drilled in Florida, but three permits were secured from the State of Florida. Our capital spending in Florida for the year ended December 31, 2008 was $11 million.
The Lazy JL Field was acquired in January 2007. The field has 50 active wells with a 100 percent working interest. Production at the Lazy JL Field comes from two zones in the lower Spraberry formation. In 2008, our average production from the field was approximately 219 Boe/d. The field is 97 percent oil and oil quality averaged 38 degrees API. In the Lazy JL Field, our interest in estimated proved reserves as of December 31, 2008 were approximately 1.2 MMBoe and the field had a reserve life index of 13 years. We also have an overriding royalty interest of one well in an additional field in Texas, which added average production of 4 Boe/d in 2008. Our capital spending in Texas for the year ended December 31, 2008 was $3 million.
We acquired our operations in the New Albany Shale of southern Indiana and northern Kentucky in November 2007. Our operations include 21 miles of high pressure gas pipeline that interconnects with the Texas Gas Transmission interstate pipeline. There are significant acreage leasing opportunities adjacent to our Indiana/Kentucky operations. The New Albany Shale has over 100 years of production history.
We operate 210 wells in Indiana and Kentucky and hold a 100 percent working interest. In 2008, our production for our Indiana and Kentucky operations was approximately 423 Boe/d and 190 Boe/d, respectively, or 2,538 Mcf/d and 1,138 Mcf/d, respectively. Our estimated proved reserves in Indiana and Kentucky as of December 31, 2008 were 0.6 MMBoe and 0.3 MMBoe, respectively, or 3.8 Bcf and 1.7 Bcf, respectively. Our capital spending in Indiana and Kentucky for the year ended December 31, 2008 was $2 million.
The following table sets forth information for our properties at December 31, 2008, relating to the productive wells in which we owned a working interest. Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in which we have an interest, and net wells are the sum of our fractional working interests owned in the gross wells.
Developed and Undeveloped Acreage
The following table sets forth information for our properties as of December 31, 2008 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned. A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Michigan acreage at December 31, 2008 has increased as compared to reported acreage at December 31, 2007 due to a detailed review during 2008 of the acreage data provided to us as part of the Quicksilver acquisition.
Our drilling activity and production optimization projects are on lower risk, development properties. The following table sets forth information for our properties with respect to wells completed during the years ended December 31, 2008, 2007 and 2006. Productive wells are those that produce commercial quantities of oil and gas, regardless of whether they produce a reasonable rate of return. No exploratory wells were drilled during the periods presented.
Of the 116 gross wells drilled in Michigan during 2008, 44 were recompletion wells. Of the ten wells drilled in Wyoming, three were recompletion wells. Of the four wells drilled in California during 2008, two were recompletion wells. We had no wells in progress as of December 31, 2008. The one well we drilled in Texas during 2008 was a new well.
Delivery Commitments As of December 31, 2008, we had no delivery commitments.
We have a portfolio of crude oil and natural gas sales contracts with large, established refiners and utilities. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. During 2008, our largest purchasers were ConocoPhillips in California and Michigan, which accounted for 25 percent of total net sales, Marathon Oil Company in Wyoming, which accounted for 13 percent of total net sales, and Plains Marketing, L.P. in Florida, which accounted for 9 percent of total net sales.
Crude Oil and Natural Gas Prices
We analyze the prices we realize from sales of our oil and gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. The WTI price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is determined by two main factors: quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees API (a scale devised by the American Petroleum Institute) and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.
Crude oil produced in the Los Angeles Basin of California and Wind River and Big Horn Basins of central Wyoming typically sells at a discount to NYMEX WTI crude oil due to, among other factors, its relatively heavier grade and/or relative distance to market. Our Los Angeles Basin crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to NYMEX WTI. Our Texas crude is of a higher quality than our Los Angeles or Wyoming crude oil and trades at a minor discount to NYMEX crude oil prices. Our Florida crude oil also trades at a significant discount to NYMEX primarily because of its low gravity and other characteristics as well as its distance from a major refining market.
In 2008, the NYMEX WTI spot price averaged approximately $100 per barrel, compared with about $72 a year earlier. Monthly average crude-oil prices fluctuated widely during 2008, from a low of $41 per barrel for December to a high of $134 per barrel for June. For the year ended December 31, 2008, the average discount to NYMEX WTI for our California, Wyoming, Florida and Texas crude oil was $5.15, $18.86, $14.45 and $1.63 per barrel, respectively.
Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. We have entered into derivative contracts for approximately 80 percent of our current natural gas production. To the extent our production is not hedged, we anticipate that this supply/demand situation will allow us to sell our future natural gas production at a slight premium to industry benchmark prices. Prices for natural gas have historically fluctuated widely and in many regional markets are aligned with supply and demand conditions in regional markets and with the overall U.S. market. Fluctuations in the price for natural gas in the United States are closely associated with the volumes produced in North America and the inventory in underground storage relative to customer demand. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. Since January 2005, NYMEX monthly average futures price for natural gas at Henry Hub ranged from a low of $5.22 per MMBtu for September 2006 to a high of $13.45 per MMBtu for October 2005. During 2007, the average NYMEX wholesale natural gas price ranged from a low of $6.14 per MMBtu for August to a high of $7.82 per MMBtu for May. During 2008, the average NYMEX wholesale natural gas price ranged from a low of $5.79 per MMBtu for December to a high of $12.78 per MMBtu for June.
Our operating expenses are sensitive to commodity prices. We experience pressure on operating expenses that is highly correlated to commodity prices for specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes.