Oneok Partners. 10% Owner ONEOK INC /NEW/ bought 8000000 shares on 2-28-2012 at $ 57.48
North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from nonconventional resource areas, such as shale plays. Because of the relatively higher market prices of crude oil and NGLs, drilling activity is especially robust in shale plays with crude oil and NGL-rich natural gas production. As a result, we expect producers to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production. We expect inter-regional opportunities for midstream infrastructure development driven by producers who need to connect emerging production with end-use markets where current infrastructure is insufficient or nonexistent.
In 2011, producers continued to drill aggressively in a number of NGL-rich resource plays in the Mid-Continent and Rocky Mountain regions, creating a need for additional infrastructure to bring this new supply to market. The resulting increase in natural gas supply has caused lower natural gas prices, less volatility and narrower natural gas location and seasonal price differentials in the markets we serve.
Additionally, we have seen strong ethane demand from the petrochemical sector in the Gulf Coast, due to the price advantage ethane has over other feedstocks. Consequently, NGL pipeline capacity between the Conway, Kansas, and Mont Belvieu, Texas, market centers is constrained and contributes to wider location price differentials between those markets. The natural gas supply growth has also increased NGL supply in the Mid-Continent, coupled with increased demand in the Gulf Coast, resulting in decreased NGL prices in the Mid-Continent market center at Conway, Kansas, relative to prices in the Gulf Coast market center at Mont Belvieu, Texas.
Additional fractionation and pipeline capacity is needed to accommodate the growing NGL supply and demand, as well as new infrastructure to gather, process and transport growing natural gas production from both new and existing resource plays. In response to this increased production and demand for NGL products, we are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. When completed, we expect these projects to provide additional earnings and cash flows.
During 2011, we paid cash distributions of $2.325 per unit, an increase of approximately 4.3 percent over the $2.23 per unit paid during 2010. In January 2012, our general partner declared a cash distribution of $0.61 per unit ($2.44 per unit on an annualized basis), an increase of approximately 7.0 percent over the $0.57 declared in January 2011.
In January 2011, we completed an underwritten public offering of senior notes generating net proceeds of approximately $1.28 billion. During 2011, we utilized proceeds from this debt issuance, cash from operations and our commercial paper program to meet our short-term liquidity needs and to fund our capital projects. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We expect to fund our future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.
See Item 7, Managementâ€™s Discussion and Analysis of Financial Condition and Results of Operation, for information on our growth projects, results of operations, liquidity and capital resources.
Our primary business strategy is to increase distributable cash flow through consistent and sustainable earnings growth while focusing on safe, reliable, environmentally responsible and legally compliant operations for our customers, employees, contractors and the public through the following:
â€˘ Operate in a safe, reliable and environmentally responsible manner - environmental, safety and health issues continue to be a primary focus for us; our emphasis on personal and process safety has produced improvements in the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies;
â€˘ Consistent growth and sustainable earnings - we continue to increase NGL volumes gathered and fractionated in our Natural Gas Liquids segment and natural gas volumes processed in our Natural Gas Gathering and Processing segment, which generate earnings from predominately fee-based and POP contracts, as producers continue to develop NGL-rich resource plays that we serve in the Mid-Continent and Rocky Mountain areas. We are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows;
â€˘ Execute strategic acquisitions that provide long-term value - we remain a disciplined buyer of assets and continue to evaluate assets that come to market. We did not consummate any acquisitions in 2011;
Manage our balance sheet and maintain strong credit ratings - our balance sheet remains strong, ending 2011 with a capital structure of 53-percent debt and 47-percent equity. We will seek to maintain our investment-grade credit ratings; and
Attract, develop and retain employees to support strategy execution - we continue to execute on our recruiting strategy that targets colleges, universities and vocational-technical schools in our operating areas. We also continue to focus on employee development efforts with our current employees.
NARRATIVE DESCRIPTION OF BUSINESS
We report operations in the following business segments:
Natural Gas Gathering and Processing;
Natural Gas Pipelines; and
Natural Gas Liquids.
Natural Gas Gathering and Processing
Overview - Our Natural Gas Gathering and Processing segmentâ€™s operations provide nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells. We gather and process natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale and Granite Wash formations, the Mississippian Lime formation of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather and/or process natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming. The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry, natural gas that does not require processing or NGL extraction in order to be marketable; dry, natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.
In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are in the form of a mixed, unfractionated NGL stream. Our natural gas and NGLs are sold to affiliates and a diverse customer base.
Our natural gas processing operations primarily utilize field gas processing plants to extract NGLs and remove water vapor and other contaminants from the unprocessed natural gas stream. Field gas processing plants process natural gas gathered from multiple producing wells.
We generally gather and process natural gas under the following types of contracts.
POP - Under a POP contract, we retain a percentage of the NGLs and/or a percentage of the residue gas as payment for gathering, treating, compressing and processing the producerâ€™s natural gas. The producer may take its share of the NGLs and residue gas in-kind or receive its share of proceeds from our sale of the commodities. POP contracts expose us to both natural gas and NGL commodity price risks but economically align us with the producer because we both benefit from higher commodity prices, reduced costs and improved efficiencies. This type of contract represented approximately 37 percent and 35 percent of contracted volumes for 2011 and 2010, respectively. There are a variety of factors that directly affect our POP margins, including:
the percentages of products retained by us that represent NGL, condensate and residue gas sales volumes that we receive as payment for the services we provide;
transportation and fractionation costs incurred on the NGLs we retain; and
the natural gas, crude oil and NGL prices received for our retained products.
Fee - Under a fee-based contract, we are paid a fee for the services provided that is based on Btus gathered, treated, compressed and/or processed. The wellhead volume and fees received for the services provided are the main components of our margin for this type of contract. The producer typically takes its NGLs and residue gas in-kind. Our POP and keep-whole contracts also typically include fee provisions, which are a portion of the fees reported in this category. Our fee-based contracts and contract provisions primarily expose us to volumetric risk with minimal commodity price risk and represented approximately 60 percent and 61 percent of contracted volumes for 2011 and 2010, respectively.
Keep-Whole - Under a keep-whole contract, we extract NGLs from the unprocessed natural gas and return to the producer volumes of residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us. We retain the NGLs as our fee for processing. Accordingly, we must purchase and return to the producer sufficient volumes of residue gas to replace the Btus that were removed as NGLs through the gathering and processing operation, commonly referred to as â€śshrink.â€ť This type of contract represented approximately 3 percent and 4 percent of contracted volumes for 2011 and 2010, respectively, with approximately 75 percent and 85 percent, respectively, of that volume under contracts that effectively convert into fee contracts when the gross processing spread is negative.
Our revenues from this segment are derived primarily from POP and fee contracts. We expect that our capital projects will provide additional revenues from POP and fee contracts when completed. We use derivative instruments to mitigate our sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes.
Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated affiliates:
49-percent ownership interest in Bighorn Gas Gathering, which operates a major coal-bed methane gas gathering system serving a broad production area in northeast Wyoming;
37-percent ownership interest in Fort Union Gas Gathering, which gathers coal-bed methane gas produced in the Powder River Basin and delivers natural gas into the interstate pipeline grid;
35-percent ownership interest in Lost Creek Gathering Company, L.L.C., which gathers natural gas produced from conventional wells in the Wind River Basin of central Wyoming and delivers natural gas into the interstate pipeline grid; and
10-percent ownership interest in Venice Energy Services Co., L.L.C., a natural gas processing complex near Venice, Louisiana.
See Note K of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.
Market Conditions and Seasonality - Supply - Natural gas supply is affected by rig availability, operating capability and producer drilling activity, which is sensitive to commodity prices, exploration success, access to capital and regulatory control. Higher crude oil prices and advances in horizontal drilling and completion technology are having a positive impact on drilling activity in the shale areas and other resource plays, providing an offset to the less favorable supply projections in some of the conventional resource areas.
In the Rocky Mountain region, Williston Basin volumes continue to grow as drilling activity increases, driven primarily by producer development of Bakken Shale crude oil wells, which also produce associated natural gas containing significant amounts of NGLs. However, we have seen declines in natural gas volumes gathered in the Powder River Basin, which is dry gas.
In the Mid-Continent region, we have a significant amount of natural gas gathering and processing assets in western Oklahoma and southwest Kansas. We expect increased drilling activity in the Cana-Woodford Shale and Granite Wash areas of western Oklahoma and the Mississippian Lime formation of Oklahoma and Kansas to more than offset the volumetric declines in most conventional wells that supply our natural gas gathering and processing facilities.
Demand - Demand for natural gas gathering and processing services is typically aligned with the production of natural gas from natural gas plays or the associated natural gas from wells drilled in crude oil plays. Gathering and processing are nondiscretionary services that producers require to market their natural gas and natural gas liquid production. As producers continue to develop shale and other resource plays, we expect demand for our gathering and processing services to increase. Our natural gas processing plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing operating parameters at certain plants, we can reduce, to some extent, the amount of ethane and propane recovered if prices or processing margins are unfavorable.
Commodity Prices - Crude oil, natural gas and NGL prices are volatile due to changes in market conditions such as the amount of available supply, storage injection and withdrawal rates, available storage capacity and demand for our products by the petrochemical industry and other consumers. We are exposed to commodity price risk and the cost of natural gas transportation at various market locations as a result of receiving commodities through our POP contracts in exchange for our services.
Seasonality - Certain of this segmentâ€™s products are subject to weather-related seasonal demand. Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses. Warm temperatures typically drive demand for natural gas used for gas-fired electric generation needed to meet the electricity-generation demand required to cool residential and commercial properties. Demand for iso-butane and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, may also be subject to some variability as automotive travel increases and as seasonal gasoline formulation standards are implemented. During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence processing decisions.
Competition - The natural gas gathering and processing business remains relatively fragmented despite significant consolidation in the industry. We compete for natural gas supplies with major integrated oil companies, independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions. The factors that typically affect our ability to compete for natural gas supplies are:
fees charged under our gathering and processing contracts;
pressures maintained on our gathering systems;
location of our gathering systems relative to those of our competitors;
location of our gathering systems relative to drilling activity;
efficiency and reliability of our operations; and
delivery capabilities that exist in each system and plant location.
Competition for natural gas gathering and processing services continues to increase as new infrastructure projects are completed to address increased production from shale and other resource plays. We are responding to these industry conditions by making capital investments to construct and expand our assets, improve natural gas processing efficiency and reduce operating costs, evaluating consolidation opportunities to maximize earnings, and renegotiating low-margin contracts. The principal goal of the contract renegotiation effort is to improve margins and reduce risk.
Government Regulation - The FERC has traditionally maintained that a natural gas processing plant is not a facility for the transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional natural gas gathering facility status. However, we are subject to FERC regulations that require us to publicly post certain natural gas flow information on our websites. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue natural gas from our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.
Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to various degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.
See further discussion in the â€śEnvironmental and Safety Mattersâ€ť section.
MANAGEMENT DISCUSSION FROM LATEST 10K
The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. Please refer to the â€śFinancial Results and Operating Informationâ€ť and â€śLiquidity and Capital Resourcesâ€ť sections of Managementâ€™s Discussion and Analysis of Financial Condition and Results of Operation, our Consolidated Financial Statements and Notes to Consolidated Financial Statements for additional information.
Growth Projects - Drilling rig counts are higher compared with 2010, and related development activities continue to progress in many regions of our operations. We expect continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. Increasing natural gas and NGL production resulting from these activities and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market. In response to this increased production and demand for NGL products, we are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Rockies, Mid-Continent and Gulf Coast regions that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows.
See discussion of these growth projects in the â€śFinancial Results and Operating Informationâ€ť section in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.
Cash Distributions - During 2011, we paid cash distributions totaling $2.325 per unit, an increase of approximately 4.3 percent over the $2.23 per unit paid during 2010. In January 2012, our general partner declared a cash distribution of $0.61 per unit ($2.44 per unit on an annualized basis), an increase of approximately 7.0 percent over the $0.57 declared in January 2011.
Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes in March 2011 and for general partnership purposes, including capital expenditures.
Unit Split - In July 2011, we completed a two-for-one split of our common and Class B units by a distribution of one unit for each unit outstanding and held by unitholders of record on June 30, 2011. In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the unit split. We have adjusted all unit and per-unit amounts contained herein to be presented on a post-split basis.
Operating income increased approximately 60 percent during 2011, compared with 2010. The increase in operating income reflects higher net margin in our Natural Gas Liquids and Natural Gas Gathering and Processing segments.
Our Natural Gas Liquids segment benefited from more favorable NGL price differentials, as well as additional NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets. Our Natural Gas Liquids segment also realized higher exchange service margins due primarily to higher NGL gathering and fractionation volumes and contract renegotiations at higher fees with our customers. In addition, our Natural Gas Liquids segment realized higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes.
Our Natural Gas Gathering and Processing segment benefited from significantly higher realized NGL and condensate prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.
These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. Additionally, our Natural Gas Pipelines segment realized lower transportation margins due to narrower natural gas price location differentials that caused a reduction in contracted capacity primarily on Midwestern Gas Transmission.
Gain (loss) on sale of assets decreased from 2010, which reflected a $16.3 million gain on the sale of a 49-percent interest of Overland Pass Pipeline Company.
Operating costs increased for 2011, compared with 2010, due primarily to higher labor and employee-related costs associated with incentive and benefit plans, and higher ad valorem taxes, as well as higher materials and outside services expenses associated primarily with scheduled maintenance at our natural gas liquids fractionation and storage facilities. Our employees participate in compensation and benefit plans administered by ONEOK, which include ONEOKâ€™s short-term incentive and share-based compensation plans. ONEOKâ€™s share price significantly increased in 2011, resulting in increased employee-related costs to us.
Equity earnings from investments increased for 2011, compared with 2010, due to the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company in our Natural Gas Liquids segment and increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment.
Capital expenditures increased for 2011, compared with 2010, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and the purchase of leased equipment at our Bushton plant.
2010 vs. 2009 - Energy markets were affected by higher commodity prices during 2010, compared with 2009. The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel. We completed more than $2.0 billion in growth projects at the end of 2008 and in 2009. Our 2010 operating results include the benefits from a full year of our completed projects, including the following projects placed in service in 2009:
February - Guardian Pipelineâ€™s expansion and extension project in our Natural Gas Pipelines segment;
March - Grasslands natural gas processing plant expansion in our Natural Gas Gathering and Processing segment;
March - D-J Basin lateral pipeline in our Natural Gas Liquids segment;
July - Arbuckle Pipeline in our Natural Gas Liquids segment; and
October - Piceance lateral pipeline in our Natural Gas Liquids segment.
Operating income increased 7 percent in 2010, compared with 2009. The increase in operating income for the 2010 period reflects the benefit of a full year of operations of our capital projects completed in 2009, resulting in higher NGL volumes in the Natural Gas Liquids segment; higher contracted natural gas transportation capacity on the Midwestern Gas Transmission and Viking Gas Transmission pipelines in the Natural Gas Pipelines segment; and an increase in Williston Basin volumes in our Natural Gas Gathering and Processing segment. Additionally, our Natural Gas Liquids and Natural Gas Pipelines segments produced higher storage margins, primarily as a result of contract renegotiations. Operating income also included the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. Operating income also benefited from lower than estimated ad valorem taxes associated with our capital projects completed in 2009 and lower outside services costs for maintenance at our fractionators in 2009, offset partially by incremental employee-related costs and property insurance costs associated with our capital projects completed in 2009.
These increases were offset partially by lower optimization margins in the Natural Gas Liquids segment due to limited NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf Coast NGL market centers until September 2010 and less favorable NGL price differentials; and decreased margins in our Natural Gas Gathering and Processing segment from lower natural gas volumes processed and sold in western Oklahoma and Kansas, selling our bankruptcy claims with Lehman Brothers in 2009 and lower natural gas volumes gathered in the Powder River Basin in Wyoming.
Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials. Additionally, in September 2010, we began accounting for our 50-percent investment in Overland Pass Pipeline Company, which includes the Overland Pass Pipeline and the D-J Basin and Piceance lateral pipelines, as an equity investment.
Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.
Natural Gas Gathering and Processing
Growth Projects - Our Natural Gas Gathering and Processing segment is investing approximately $950 million to $1.1 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas that will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.
Williston Basin Processing Plants and related projects - Our projects in this basin include three 100 MMcf/d natural gas processing facilities: the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota. We have multi-year supply commitments and acreage dedications for all the capacity of the Garden Creek and Stateline I plants and for approximately 75 percent of the Stateline II plantâ€™s capacity. In addition, we will expand and upgrade our existing gathering and compression infrastructure and add new well connections associated with these plants. The Garden Creek plant, which was placed in service in December 2011, and related infrastructure projects are expected to cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant, which is expected to be in service by the third quarter of 2012, and related infrastructure projects are expected to cost approximately $300 million to $355 million, excluding AFUDC. The Stateline II plant, which is expected to be in service during the first half of 2013, and related infrastructure projects are expected to cost approximately $260 million to $305 million, excluding AFUDC.
Horizontal wells drilled in the Williston Basin are economically justified by producers primarily by crude oil economics. In addition, we expect our commodity price exposure to increase, particularly to NGLs and natural gas, as our equity volumes increase under our POP contracts with our customers in the Williston Basin.
Cana-Woodford Shale projects - In 2010, we completed projects totaling approximately $38 million in the Cana-Woodford Shale development in Oklahoma, which included the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma, as well as new well connections to gather and process additional Cana-Woodford Shale natural gas volumes.
In both the Williston Basin and Cana Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells. These wells tend to produce at higher initial volumes; however, they generally have higher initial decline rates than conventional vertical wells, but the decline curves flatten out. These wells are expected to have long-lasting reserves. The routine growth capital needed to connect to new wells and expand our infrastructure is expected to increase compared with our previous experience.
2011 vs. 2010 - Natural gas transportation capacity contracted decreased due primarily to lower subscribed capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets it serves.
2010 vs. 2009 - Natural gas transportation capacity contracted increased due primarily to increased capacity on Midwestern Gas Transmission due to a new interconnection with the Rockies Express Pipeline, Viking Gas Transmissionâ€™s Fargo lateral, and Guardian Pipeline expansion projects completed in 2009.
Our pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. The development of shale gas and other resource plays has continued to increase available natural gas supply and has caused natural gas prices to decrease and location and seasonal price differentials to narrow. As additional supply is developed, we expect producers to demand incremental services in the future to transport their production to market. The abundance of shale gas supply and new regulations on emissions from coal-fired electric-generation plants may also increase the demand for our services from electric-generation companies if they were to convert to a natural gas fuel source. Conversely, contracted capacity by certain customers that are focused on capturing location or seasonal price differentials may decrease in the future due to narrowing price differentials. Overall, we expect our fee-based earnings to remain relatively stable in the future as the development of shale and other resource plays continue.
Natural Gas Liquids
Growth Projects - Our growth strategy in the Natural Gas Liquids segment is focused around the oil and natural gas drilling activity in shale and other resource plays from the Rockies through the Mid-Continent region into Texas. Increasing natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly over the next five years and international demand for propane is expected to impact the NGL market in the future. Our Natural Gas Liquids segment is investing approximately $1.7 billion to $2.2 billion through 2014. This investment will accommodate the gathering and fractionation of growing NGL supplies from the shale and other resource plays across our asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast. The execution of these capital investments aligns with our focus to grow fee-based earnings. Our supply commitments from producers and natural gas processors associated with our growth projects will provide incremental and long-term fee-based earnings to our exchange services business. Over time, these growing fee-based volumes will fill a portion of the capacity used in 2011 to capture the price differentials between the two market centers. In addition, we believe the price differentials between the Mid-Continent and Gulf Coast market centers will narrow over the long-term as new fractionators and pipelines, including our MB-2 fractionator and Sterling III pipeline, begin to alleviate constraints impacting NGL prices and the location price differential between the two market centers.
Sterling III Pipeline - We plan to build a 570-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Texas Gulf Coast. The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas. The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from our natural gas liquids infrastructure at Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas. We have multi-year supply commitments from producers and natural gas processors for approximately 75 percent of the pipelineâ€™s capacity. Additional pump stations could expand the capacity of the pipeline to 250 MBbl/d. Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late the same year.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Unit Split - In June 2011, the board of directors of our general partner approved a two-for-one split of our common and Class B units. The two-for-one unit split was completed on July 12, 2011, by a distribution of one unit for each unit outstanding and held by unitholders of record on June 30, 2011. In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the unit split. As a result of this unit split, we have adjusted all unit and per-unit amounts contained herein to be presented on a post-split basis.
Growth Projects - Drilling rig counts are higher and related development activities continue to progress in many areas of our operations compared with 2010. Increasing natural gas and NGL production resulting from these activities and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market. In response to this increased production and demand for NGL products, we have announced $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows.
See discussion of these growth projects in the â€śFinancial Results and Operating Informationâ€ť section for our Natural Gas Gathering and Processing and Natural Gas Liquids segments.
Cash Distributions - In October 2011, our general partner declared a cash distribution of $0.595 per unit ($2.38 per unit on an annualized basis) for the third quarter of 2011, an increase of 1 cent from the previous quarter, which will be paid November 14, 2011, to unitholders of record at the close of business on November 7, 2011.
Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes due March 2011 and for general partnership purposes, including capital expenditures.
Partnership 2011 Credit Agreement - On August 1, 2011, we entered into the Partnership 2011 Credit Agreement, which replaced the Partnership Credit Agreement.
Thank you. Good morning and welcome, everyone. As we begin this morning's conference call, I remind you that any statements that might include ONEOK, or ONEOK Partnersâ€™ expectations or predictions should be considered forward-looking statements, which are covered by the Safe Harbor provision of the Securities Acts of 1933 and 1934. It is important to note that actual results could differ materially from those projected in such forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to ONEOK's and ONEOK Partnersâ€™ filings with the Securities and Exchange Commission.
And now, John Gibson, who serves as CEO of ONEOK, and Chairman, President and CEO of ONEOK partners. John?
Thanks, Dan and good morning, everyone. Thank you for participating in our call today and for your continued interest and investment in ONEOK and ONEOK Partners. Joining me today are Jim Kneale, President and Chief Operating Officer for ONEOK and ONEOK Partners and Curtis Dinan, Chief Financial Officer for both ONEOK and ONEOK Partners.
Our agenda this morning is following a few opening remarks, Curtis will review ONEOK Partners' financial performance followed by Jim who will review the partnership's operating performance. Then we will return back to Curtis who will review ONEOK's financial performance and Jim will then review ONEOK's operating performance. Then I will make a few closing comments and conclude our call with a question and answer period.
As indicated in our earnings news release yesterday, ONEOK had a strong second quarter with exceptional performance by the ONEOK Partners segment and solid results from the distribution segment. However, our energy services segment experience lower second quarter results, primarily as a result of lower transportation margins. ONEOK Partnersâ€™ second quarter results were up more than 60%, benefiting from higher realized commodity prices and increased processed volumes in the natural gas gathering and processing business. New supply connections and increased fractionation volumes drove the increases in our NGL gathering and fractionation business. And the incremental earnings from our North system, the NGL and refined petroleum products pipeline system we acquired last October benefited our NGL pipelines business. The distribution segment was up slightly in the second quarter as a result of the newly implemented capital and expense recovery mechanisms in Oklahoma.
Jim will review each of the segment's second quarter results in more detail in a few minutes. First, let us take a more detailed look at ONEOK Partners. Curtis Dinan will review the financial highlights. Curtis?
Thank you, John. Good morning, everyone. ONEOK Partners delivered exceptional results in the second quarter.
Net income increased 63% to $155 million or $1.46 per unit compared with $95 million or $0.97 per unit in the second quarter of 2007. Distributable cash flow increased to $177 million compared with $122 million in the second quarter of 2007. During the second quarter of 2008, all four of our segments showed improved results compared with 2007. Our natural gas gathering and processing segment had an exceptional quarter, benefiting primarily from strong commodity prices.
For the balance of 2008, in the natural gas gathering and processing segment, we have hedged prices on 74% of our expected production on both NGLs and condensate at an average price of $1.38 per gallon. We have also placed hedges for the remainder of the year on 54% of our expected natural gas volumes at $9.35 per MMBTU. Looking forward to 2009, we have placed hedges on 30% of our expected NGL and condensate production at an average price of $2.22 per gallon. We review each product separately and are continually looking for opportunities to minimize commodity price risk. We use a combination of commodity specific swaps and over-the-counter basis swaps to hedge our commodity price exposure. I want to emphasize that we do not use crude oil futures to hedge our natural gas liquid sales, a practice commonly referred to as dirty hedges. The balance of the partnership's revenues is primarily fee-based, so hedging activities are limited to our natural gas gathering and processing segment.
During the first half of 2008 the partnership has invested $504 million on growth capital projects, primarily for the Overland Pass Pipeline and related NGL infrastructure upgrades, the Arbuckle Pipeline, and the Guardian Pipeline extension. These investments have been financed with our revolving credit agreement and the equity offering completed in March of this year. With $76 million of cash on hand and approximately $850 million available under the revolving credit agreement at July 31, the partnership is well positioned to continue to fund its growth capital projects that will begin contributing incremental EBITDA later this year.
This July, ONEOK Partners increased its quarterly distribution to an annualized rate of $4.24 per unit. This is our tenth consecutive distribution increase since the drop down of the ONEOK assets in April of 2006. During this period, the partnership has increased distributions by 33%, demonstrating our commitment to growing unit holder distributions.
And lastly, we raised our 2008 net income guidance to the range of $5.20 to $5.60 per unit, an increase from our previous guidance of $4.10 to $4.60 per unit. We also raised the expected distributable cash flow to a range of $585 million to $625 million. These increases reflect the strong first half performance in all four segments, continued volume growth in both the natural gas and natural gas liquids businesses, and continued strong commodity prices. The average unhedged prices for 2008 were updated to $120 per barrel for crude oil, $1.65 per gallon for composite NGLs, and $9.20 per MMBTU for natural gas. But, as I mentioned, the majority of our commodity exposure in the partnership is hedged for the remainder of 2008.
John, that concludes my remarks regarding the partnership's financials.
Thanks, Curtis. Now let's turn to Jim Kneale, ONEOK Partnersâ€™ President and Chief Operating Officer to discuss the partnership's operating performance. Jim?
Thanks, John, and good morning. As John and Curtis mentioned, the partnership had an outstanding second quarter. Let us review each of the business segments.
The natural gas gathering and processing segment's second quarter operating income increased 65% and year-to-date results increased 76% compared with the same periods in 2007. Higher NGL crude oil and natural gas prices were the primary drivers of these increases. The segment also benefitted from higher throughput in 2008. Increased drilling activity continues to provide additional opportunities to replace natural production declines and for growth. So far this year, we have connected over 200 wells to our system, a 15% increase over the same period in 2007. Our contract mix by volume has remained relatively unchanged the past two years at 60% fee-based, 32% of proceeds, and 8% keep hold. We are pleased with the progress we have made in the restructuring of the contracts, providing a more stable earning stream while allowing upside potential, and we do not expect material changes to our existing mix in the future. As Curtis mentioned, we have also been proactive through hedging to minimize the risk associated with the commodity price volatility and provide for more predictable performance on both our percent of proceeds and keep hold contracts.
The natural gas pipeline segment second quarter 2008 operating income results increased 50% and year-to-date results improved more than 20% compared with the same periods in 2007. The growth reflects an increase in transportation margins, which came primarily from higher throughput and the impact that higher natural gas prices had on our net retained fuel position. Storage margins also improved compared with the second quarter of 2007, due primarily to higher storage fees as a result of new and renegotiated contracts. Another contributing factor to the quarter's growth was lower operating costs, which decreased 17% from the same period last year, mainly due to lower ad valorem taxes and timing of operations and maintenance costs.
This segment has begun construction on the guardian pipeline expansion in the Green Bay, Wisconsin. We are now estimating the cost to be in a range of $277 million to $305 million. As with any construction project of this magnitude, cost and completion dates are affected by a number of regulatory and environmental variables, in addition to factors such as weather, the amount of rock encountered, and increasing right of way cost. Changes in the right of way cost along the Guardian route are to some degree the result of rising corn and soybean prices, which have affected the value of the land. We will continue to keep you updated on our progress, but we currently anticipate the pipeline being in service by year-end.
Now let us take a look at the two natural gas liquid segments, both of which had another outstanding quarter. The Natural Gas Liquids â€“ Gathering & Fractionation segment's second quarter operating income increased 31% over the same period in 2007. Driving most of the increase was higher throughput from continued NGL supply growth in the midcontinent. 2008 second quarter results also benefited from wider regional NGL price differentials between Conway and Mont Belvieu, offset by narrow product prices differentials between iso and normal butane. Year-to-date results improved 36% compared with the same period in 2007. Again, the leading driver was increased throughput across the system. Volumes gathered increased 16% and volumes fractionated increased 14%. Also contributing to the earnings increase were wider regional NGL price differentials.
Our continued focus on growing NGL supplies has led to higher asset utilization rates that now exceed 90%. This supply growth is one of the key drivers for our NGL storage fractionation and pipeline infrastructure expansion projects in Kansas and Oklahoma. In the second quarter of 2008, we completed most of these expansion projects. The cost increased slightly from the $216 million previously announced, mainly as a result of further increasing the capacity of the previously-idled Bushton, Kansas fractionator by an additional 30,000 barrels per day. Initially, we planned to increase the capacity of the fractionator from 80,000 to 120,000 barrels per day. However, due to increased demand, we increased the total capacity to 150,000 barrels per day. Costs were also slightly higher due to increases experienced in construction labor rates and material costs as well as delays from frequent heavy rainfall this spring.
Also, as a part of these expansions, we have upgraded the storage at Bushton to accommodate additional ethane propane product and constructed 135-mile purity product distribution pipeline from the Bushton complex to our Medford, Oklahoma complex where product can be moved to Mont Belvieu, Texas through our existing and newly-expanded Sterling distribution pipeline. This increased infrastructure capacity, much of which is currently online, will accommodate our new NGL supplies from the Rockies as well as future growth in the midcontinent. Upon final completion of these projects in the third quarter of 2008, we will have increased our total fractionation capacity to 549,000 barrels per day, up from 399,000 barrels per day.
Our Natural Gas Liquids Pipelines segment also had a great second quarter, with operating income increasing 18% over the same period in 2007 and NGL volumes transported increasing 35% over that same time. For the first half of 2008, operating income increased 39% and NGL volumes transported increased more than 40% or 89,000 barrels per day. Most of these increases are due to the addition of the 1,600-mile NGL and refined petroleum products pipeline system we acquired in October 2007 as well as continued supply growth that I previously talked about in our NGL gathering & fractionation segment.
Now let us review the status of some of our largest projects in our natural gas liquids business. We continue to make progress on the construction of the Overland Pass Pipeline. We have completed approximately 730 of the 760 miles of the pipeline. As you may recall, the Wyoming office of the Federal Bureau of Land Management requested that we temporarily idle construction in certain restricted areas to accommodate the seasonal migration patterns of big game animals, the nesting activities of birds of prey, and the sage grouse habitat. As of August 1st, both the sage grouse and raptor restrictions have expired and construction in these restricted areas is now underway. However, we may continue to be affected in certain areas due to the potential presence of nesting birds. As the nesting activities run their natural course, we still expect to have much of the pipeline operational beginning in the third quarter with the remainder of the line coming on in the fourth quarter.
The current total cost estimate for the Overland Pass is between $575 million and $590 million, reflecting the anticipated 10% cost increase caused by the delays that we mentioned during our conference call last quarter. Although our costs have increased, so have the throughput commitments, resulting in continued very favorable economics for this project. Overland Pass will provide much needed NGL take away capacity in the Rockies. Potential new development in the region continues to exceed our original expectations. The volumes committed to Overland Pass Pipeline are approaching 140,000 barrels per day, which includes the previously announced Williams commitment for 60,000 barrels, with growth prospects under development for up to an additional 60,000 more barrels per day over the next three to five years. We have previously mentioned our ability to expand the pipeline with minimal cost to 220,000 barrels per day; and after further engineering evaluation, we now have the capability to expand Overland Pass up to 255,000 barrels per day, with additional pump facilities.
Construction of the Arbuckle Pipeline is well under way. In our last call, we mentioned timing and cost could be affected by factors such as the uncertainty of weather, right of way acquisitions and construction labor. Pipeline right of way costs have increased dramatically in the recent months as Barnett Shale development has increased with the demand and costs for easements to unprecedented levels. We recently completed negotiations with pipeline contractors, providing us with better visibility into the expected labor cost, compared with what we had estimated more than a year-and-a-half ago. To reflect these increased costs, we have updated the pipeline project estimate, which we now expect to be $340 million to $360 million.
Much like Overland Pass, new processing plant development and the timing of NGL volumes coming online along Arbuckle are also exceeding our original estimates. While the pipeline is designed with a capacity to transport 160,000 barrels per day of unfractionated NGLs, it can be expanded to over 210,000 barrels per day with additional pump facilities. At the time of start up in 2009, we currently expect Arbuckle to be shipping approximately 65,000 barrels per day of dedicated NGLs to our Mont Belvieu fractionator and other facilities in the Texas Gulf Coast, with another 20,000 barrels per day expected from new plant dedications that are currently under negotiation. Based upon our current commitments and producers' projections of increased production, and indications of interest from NGL producers, we are projecting Arbuckle throughput to reach its maximum capacity of 210,000 barrels per day within the next three to five years as the development of new processing plants continue in Oklahoma, North Texas, and in the Barnett Shale.
As Curtis mentioned, we are increasing the partnership's earnings and cash flow guidance for 2008. In addition to strong results in the first half of 2008 in all four business segments, we expect commodity prices to be higher than the levels we provided in our previous guidance, benefiting the natural gas gathering and processing and pipeline segments. As we have mentioned earlier, we have hedges in place for the rest of 2008 on the majority of our commodity exposure in the partnership. Higher commodity prices, combined with higher NGL throughput in our natural gas liquids gathering and fractionation segment will more than offset the impact of Overland Pass Pipeline coming on later than originally anticipated.
Looking at the EBITDA projections for the growth projects that we have previously provided, the numbers have improved due to increased volume projections on several of the projects and moved around somewhat, primarily due to the delay in Overland Pass. The 2008 EBITDA projection has been reduced about $24 million due to the delay on Overland Pass, which is reflected in our revised 2008 guidance for the NGL pipeline segment. The projection for 2009 EBITDA for the growth project is unchanged at $260 million. The 2010 projection of $300 million is now estimated at $360 million, up 20%. We expect this number to grow in 2011 and beyond as NGL volumes continue to grow.
Finally, I'd like to recognize the partnership's Mont Belvieu, Texas fractionator employees who were recognized last month by the Occupational Safety and Health Administration for achieving three years of excellence in employee health and safety.
John, that concludes my remarks.
Thanks, Jim. Before we turn our focus to ONEOK, I'd like to make a few additional comments on the partnership's growth activities.
As you've just heard, ONEOK Partners is continuing to make good progress on its internally-generated growth projects. And as I have mentioned before, we have identified a slate of new projects, not yet announced, that will require capital investments averaging $300 million to $500 million a year between 2010 and 2015. Managing these costs and schedules for these projects remain a top priority for me and the rest of the management team. I'd like to put the cost increases and delays that we have experienced on some projects into perspective.
More than two years ago, we purchased the pipe for our three announced NGL pipeline projects â€“ Overland Pass, the Piceance Lateral, and the Arbuckle Pipeline. This was a good decision for our company, as it enabled us to avoid the significant run up in steel prices that the industry has experienced and is facing today. In fact, we estimate this decision saved almost $100 million of additional capital costs. What we did not forecast correctly, however, was the increase in labor costs we have incurred since the Overland Pass and Arbuckle Pipeline projects were first planned and announced several years ago. And, as we have shared with you before, Overland Pass has also experienced some regulatory delays. These two factors alone have contributed to most if not all of the cost increases and start up delays on Overland Pass.
In hindsight, we should have reacted more quickly at the beginning of the project to resolve a regulatory delay that affected the receipt of our initial permit; a delay that resulted in our having to construct portions of the pipeline during one of Wyoming's harshest winters in a generation. The delay in receiving our permit not only delayed our pipeline start up, it also added the additional labor costs associated with winter construction. So on Overland Pass, the lesson learned was to focus the necessary resources on the front end of the project to better understand both regulatory and wildlife issues.
On Arbuckle Pipeline, the initial cost estimate was developed more than a year-and-a-half ago. We underestimated the magnitude of the labor cost increases we have experienced and the difficulty and cost of acquiring right of way in the Barnett Shale area near Forth Worth, where we have been buying easement by the foot rather than by the rod. While the steel cost increase did not affect the cost of pipe for Arbuckle, these increases did have an effect on the cost of valves and fittings.
Both Overland Pass and Arbuckle are still economically attractive projects, provide a much-needed service for producers and processors, and are key to our growth in the NGL sector. Even with these increased costs, these projects remain very attractive investments, principally because of the hard work and tenacity of our commercial teams as they have secured more NGL volumes that will flow earlier than we initially anticipated. This has allowed us to expand the capacity of and throughput commitments on these two pipelines to offset the increased costs and avoid any adverse effect on either project's economics, while again, meeting the needs of our customers.
These current announced projects still provide us with attractive returns at an equivalent multiple of EBITDA of six times or better; or said another way, an unlevered pre-tax return on invested capital in the range of 12% to 14%. As Jim mentioned, the timing of the EBITDA from these projects has shifted somewhat with 2010 EBITDA expected to be approximately 20% higher to $360 million from $300 million. And EBITDA from these projects will continue to ramp up beyond 2010.
Now let us turn our focus to ONEOK, where Curtis will review the second quarter financial highlights. Curtis?
Thanks, John. ONEOK's net income in the second quarter of 2008 was $42 million or $0.39 per diluted share, a 19% increase compared with net income of $35 million or $0.31 per diluted share in 2007. As Jim will discuss in more detail, the distribution segmentâ€™s operating income was comparable with 2007, while energy servicesâ€™ operating income was lower than expected, primarily as a result of reduced transportation margins.
As previously stated, our ONEOK Partners segment performed very well during the quarter. Following the partnership's recent distribution announcement, its annualized distribution has increased by $0.24 per unit when compared with what was paid a year ago. This distribution increase results in an additional $10.2 million of annual cash flow from the limited partner units that ONEOK owns. Also compared with one year ago, the incentive distributions ONEOK receives as general partner have increased by $26 million annually. Furthermore, with the growth and earnings anticipated at ONEOK Partners as a result of the current slate of growth projects, we expect future distribution increases at the partnership, which will continue to create earnings and cash flow growth for ONEOK.
Standalone cash flows from operations, excluding the effects of working capital, exceeded capital expenditures and dividends by $95 million for the first half of 2008. For the full year of 2008, we anticipate that free cash flows will be in the $180 million to $200 million range, giving us additional investment flexibility. ONEOK ended the second quarter with approximately $680 million of commercial paper outstanding, and approximately $570 million of natural gas in storage. With the increase in natural gas prices, we have experienced an increase in margin calls related to our hedges used in our energy services segment. Additionally, as we inject gas in storage for use in the upcoming heating season, and hedge our transportation positions, we expect our working capital requirements to increase compared with prior years.
To provide the liquidity to meet these higher working capital demands, we have secured a $400 million, 364-day credit agreement effective today. The 364-day credit agreement, combined with our existing $1.2 billion credit facility, will be used to support our commercial paper program. Based on current prices and the amount of gas we have already injected in storage, we expect that our working capital needs for the upcoming heating season to peak at approximately $1.3 billion to $1.4 billion during the first quarter of 2009.
We have received inquiries recently from various stakeholders regarding our exposure to the bankruptcy filing by Sim Group and certain of its subsidiaries. These inquires have centered on reports listing ONEOK and ONEOK Partners as creditors of Sim Group. ONEOK Partners has sold condensate and natural gas liquids products to Sim Group in the ordinary course of business and ONEOK has provided nominal natural gas utility services to various Sim Group locations. The receivables from product sales are secured by letters of credit issued by double-A rated National Bank. Net of these letters of credit, we do not expect ONEOK or ONEOK Partners to have a material exposure to Sim Group. Our limited financial exposure to Sim Group is a direct result of the diligence of the employees in our credit group and the established policies and procedures we follow. We remain diligent in our credit review practices and have also reduced our credit exposures to other counter parties where we felt prudent.
And lastly, we have increased ONEOK's net income guidance for 2008 and narrowed the range to $2.90 to $3.10 per diluted share from the previous guidance of $2.75 to $3.15 per diluted share. The distribution segment's operating income guidance increased slightly to reflect its strong performance in the first half of 2008. We have lowered the operating income guidance of our energy services segment as a result of lower than expected transportation, storage, and marketing margins. And, as we have discussed, our ONEOK Partners segments' operating income guidance has increased, bringing additional earnings and cash flow to ONEOK.
John, that concludes my remarks.
Thank you, Curtis. And now Jim Kneale will review ONEOK's operating performance. Jim?
Thanks, John. I've already talked about the ONEOK Partners segments, so let us start with energy services. As Curtis mentioned, earnings from this segment were below our expectations. We experienced an operating loss of $4.4 million during the second quarter, compared with income of $10.2 million in the same period last year. As we have talked about in the past, the energy services segment typically experiences a seasonal earnings pattern that follows the profile of our largest customers, the LBCs, which experience higher earnings the first and fourth quarters and lower earnings in the second and third quarters. We continue to sign up additional 2008, 2009 winter season no notice peaking contracts with our LDC customers, who see tremendous value in this service. We expect our contracted service commitments to meet or exceed last year's.
However, as we have stated before, this business is not immune to this challenging pricing environment. Our second quarter earnings decrease was primarily driven by the contraction of the transportation basis differential between the Rocky Mountain and midcontinent regions. Although we had most of this basis hedged to provide a little more color, the market basis differential was $0.62 in this just completed second quarter versus $2.72 in the same period last year. Transportation margins account for a little more than a quarter of our operating income on an annual basis. Also, during the second quarter, there was little price volatility despite the significant rise in the value of natural gas. Natural gas volatility in the quarter averaged less than 40%. The continual rise in prices during the quarter provided us very low opportunity to optimize around our least asset positions, similar to what we experienced in the first quarter. So far, the third quarter has shown some increase in volatility, which may provide us with some optimization opportunities. Summer to winter storage spreads have also remained narrow. For example, the September to December 2008 NYMEX storage spreads are in the $0.90 range. As a result, we have lowered our four-year earnings guidance in the segment to $142 million. This guidance contemplates that storage spreads will widen later in the year to the $1.50 to $1.80 per MCF range and that natural gas price volatility will also increase to a more historical level. Although we are disappointed with the results this quarter, we understand the reasons behind them and are encouraged with our growing no notice contract portfolio.
Now let us talk about the distribution segment. The distribution segment delivered solid results for the quarter as margins increased and we successfully managed operating costs. Second quarter retail volumes reflected seasonal consumption patterns and were down slightly compared with the prior year. Year-to-date retail volumes were consistent with last year and transportation volumes increased for both the quarter and year-to-date period because of addition of new customers and increased usage. Our rate mechanisms continue to provide earning stability through timely capital and expense recovery. The Oklahoma capital recovery mechanism, effective in March of this year, contributed approximately $2.3 million in margins for the quarter and is projected to contribute $7.6 million in total for 2008.
We continued to execute our strategy of filing smaller, more frequent rate recovery mechanisms. On July 30th, we requested approval from the Oklahoma Corporation Commission to recover an additional $5 million annually for incremental capital investments. If approved as proposed, this capital recovery mechanism will contribute $12.6 million of annual margin in the future. Also in July, the Oklahoma Corporation Commission approved an expense recovery mechanism that will allow collection of an additional $7.2 million for pipeline integrity management costs that we had previously incurred and deferred. Operating results in Texas improved due to the benefit of the $3.1 million annual rate settlement in our El Paso jurisdiction, along with one month's benefit of the South Texas rate case. During the quarter, we filed a $1.1 million application for capital recovery in El Paso, accompanied by capital recovery and cost of service adjustments in some of our smaller Texas jurisdictions.
While our bad debt levels are trending favorably in comparison with regional and national industry benchmarks, we are taking additional proactive measures to minimize future bad debt cost, given the projections of higher commodity prices this winter. Actions underway include a risk mitigation strategy that incorporates education, customer programs, and regulatory and operational initiatives. We already have fuel-related bad debt recovery mechanisms that cover the Kansas jurisdiction, our coldest territory, and some of our Texas jurisdictions, our warmest territories. And yesterday, we filed for fuel-related bad debt recovery in Oklahoma, our largest service territory. Our integrated strategy in the distribution segment focused on rates, cost control, and growth through efficient capital investment has continued to deliver positive results, and we remain committed to that strategy.
On a final note, we are pleased to be recognized as leading performers in the 2008 American Gas Association Operations Best Practices Benchmarking Program for emergency response. All three of our utilities ranked in the top quartile, demonstrating our continued commitment to safety and operational excellence.
John, that concludes my remarks.
Thanks, Jim. Before opening it up to questions, let me make just a few additional comments.
As discussed, we have updated and increased both ONEOK and ONEOK Partnersâ€™ 2008 earnings and guidance. The increases reflect the strong first half performance of ONEOK Partners and the expectation that the partnership will continue to benefit from volume growth in both natural gas and natural liquids businesses as well as the continuing strong commodity prices, which even though currently lower than the earlier highs this year, are still expected to be significantly higher than last year's levels. We are also raising guidance for distribution, reflecting our strong first half performance in this segment, but are lowering energy services guidance to reflect the lower first half performance and the lower storage transportation and marketing margins we anticipate for the balance of the year. Although it is typical for this segment to experience lower earnings in the second and third quarters, we have and we will continue to review this segment's performance, particularly the impact that lower natural gas price volatility and seasonal storage differentials will have on its future earnings potential.
One final note on energy services, the employees in this business have performed exceptionally and have not been content to just accept the market conditions we are experiencing. They are conducting a thorough review of all aspects of the business, looking for opportunities to mitigate the adverse market conditions and build a better and stronger business.
ONEOK's updated guidance also illustrates the benefits that ONEOK receives from its general partner and its 47.7% interest in ONEOK Partners. Our interests are clearly aligned, demonstrating that ONEOK Partners is ONEOK's growth vehicle. We are pleased with the quarter's performance and as our increased guidance indicates, very confident that we are well positioned to maintain that momentum and continue to grow in the future. Our success this quarter and year in and year out is the result of the contributions and commitment of our 4,500 plus employees. Without their hard work, our performance would not have been possible. My thanks to all of them.
Operator, we are now ready for questions.