Exhibit 99.01
EXCERPTS FROM OFFERING MEMORANDUM
RISK FACTORS
You should carefully consider the risk factors described below and the other information included in this offering memorandum before investing in the notes. Any of the risk factors set forth below could significantly and adversely affect our business, prospects, financial condition and results of operations. As a result, you could lose a part or all of your investment. Additional risks and uncertainties not currently known to us or that we currently view as immaterial may also impair our business operations.
Regulatory Risks
Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, consolidated financial position, or liquidity.
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife mortality, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.
On March 5, 2009, the U.S. Environmental Protection Agency (“EPA”) initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing amendments to the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engine Maximum Achievable Control Technology (“RICE MACT Amendments”). Depending on the final regulations that may be enacted by the EPA for the RICE MACT Amendments, our facilities will likely be impacted. The costs we may incur to comply with these regulations, including the testing and modification of the affected engines, are uncertain at this time. The current proposed effective date is three years from the effective date of the final rules.
Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone of 0.08 parts per million (“PPM”). In March 2008, the EPA lowered the ambient primary and secondary standards to 0.075 PPM. Oklahoma had until March 2009 to designate any areas of non-attainment within the state, based on ozone levels in 2006 through 2008. Following the state’s designation, the EPA was expected to determine a final designation by March 2010. States were to be required to meet the ambient standards between 2013 and 2030, with deadlines depending on the severity of their ozone level. Oklahoma City and Tulsa were the most likely areas to be designated non-attainment in Oklahoma. On September 16, 2009, the EPA announced that they would reconsider the 2008 national primary and secondary ozone standards to ensure they are scientifically sound and protective of human health. The EPA plans to propose any revisions to the ozone standards by December 2009 and expects to issue a final
decision by August 2010. The EPA also proposed to keep the 2008 standards unchanged for the purpose of attainment and non-attainment area designations. We cannot predict the final outcome of this evaluation or its timing or affect on our operations.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.
There also is growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation and regulation at the federal level, actions at the state level, litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. Recently, two federal courts of appeal have reinstated nuisance-type claims against emitters of carbon dioxide alleging that such emissions contribute to global warming. On April 17, 2009, the EPA issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. The proposed finding identified six greenhouse gases that pose a potential threat: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. The EPA is considering public comments on the proposed finding. On September 15, 2009, the EPA proposed rules to reduce greenhouse gas emissions from light-duty vehicles. Final adoption of the proposed standards for light-duty vehicles is contingent on the EPA first finalizing its proposed endangerment finding for greenhouse gas emissions from motor vehicles.
In June 2009, the American Clean Energy and Security Act of 2009 (sometimes referred to as the Waxman-Markey global climate change bill) was passed in the U.S. House of Representatives. The bill includes many provisions that would potentially have a significant impact on us and our customers, including a cap and trade regime. Although proposals have been introduced in the U.S. Senate, including a proposal that would require greater reductions in greenhouse gas emissions than the American Clean Energy and Security Act of 2009, it is uncertain at this time whether, and in what form, legislation will be adopted by the U.S. Senate. Both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy. Compliance with any new laws or regulations regarding the reduction of greenhouse gases could result in significant changes to our operations, significant capital expenditures by us and a significant increase in our cost of conducting business.
On September 22, 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The new reporting requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as
large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain of our facilities. The rule requires the collection of data beginning on January 1, 2010 with the first annual reports due to the EPA on March 31, 2011. Certain reporting requirements included in the initial proposed rules that may have significantly affected capital expenditures were not included in the final reporting rule. Additional requirements have been reserved for further review by the EPA with additional rulemaking possible. The outcome of such review and cost of compliance of any additional requirements is uncertain at this time.
On September 30, 2009, the EPA proposed two rules related to the control of greenhouse gas emissions. The first proposal, which is related to the prevention of significant deterioration and Title V tailoring, determines what sources would be affected by requirements under the Federal Clean Air Act programs for new and modified sources to control emissions of carbon dioxide and other greenhouse gas emissions. The second proposal addresses the December 2008 prevention of significant deterioration interpretive memo by the EPA, which declared that carbon dioxide is not covered by the prevention of significant deterioration provisions of the Federal Clean Air Act. The outcome of these proposals is uncertain at this time.
Oklahoma has not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in this state have declared support for state and federal action on climate change issues. We are a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions. If legislation or regulations are passed at the federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases to address climate change, this could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates.
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions.
The construction by us of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond our control and may require the expenditure of significant amounts of capital. These projects, once undertaken, may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand an existing pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues or cash flows until the project is completed. In addition, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas, we often do not have access to third-party estimates of potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent we rely on estimates of future production in deciding to construct additions to our systems, those estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect our results of operations, consolidated financial position and
cash flows. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and we may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our consolidated financial position, results of operations and cash flows could be adversely affected.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Our natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938, but the FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking and capacity release and its promotion of market centers, may indirectly affect intrastate markets. In recent years, the FERC has aggressively pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue these same objectives as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business.
Our natural gas transportation and storage operations are subject to regulation by the FERC pursuant to Section 311 of the Natural Gas Policy Act (“NGPA”), which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our transportation and storage facilities, including a reasonable return, and an adverse impact on our consolidated financial position, results of operations or cash flows.
The FERC has jurisdiction over transportation rates we charge for transporting natural gas in interstate commerce under Section 311 of the NGPA. Rates to provide such service must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every three years.
Effective April 1, 2009, we began offering a firm Section 311 service in our East Zone. Offering this service required the filing of a new rate case at the FERC to establish rates for the firm service. Accordingly, on March 27, 2009, we filed a petition for rate approval with the FERC to set the maximum rates for our new firm East Zone Section 311 transportation service and to revise the rates for our existing East and West Zone interruptible Section 311 transportation service. In anticipation of offering this new service, we had filed a revised Statement of Operating Conditions Applicable to Transportation Services (“SOC”) with the FERC to describe the terms, conditions and operating arrangements for the new service.
The maximum rate for the new firm East Zone Section 311 transportation service was effective April 1, 2009. The revised zonal rates for the Section 311 interruptible transportation
service became effective June 1, 2009. The rates for both the firm and interruptible Section 311 service are being collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the SOC filing and some additionally filed protests. We have filed answers to the interventions and protests in both matters. On August 3, 2009, the FERC Staff served data requests on us seeking additional information regarding various aspects of the filing. We submitted responses to FERC Staff’s data requests in August, September and October 2009. On August 19, 2009, the FERC issued an order extending the time for action until it can make a determination whether our rates are fair and equitable or until the FERC determines that formal proceedings are necessary. The August 19, 2009 order also directed the FERC Staff to report to the FERC by December 29, 2009 on the status of settlement negotiations.
We cannot predict what the settlement terms will be for these matters or, if not settled, what determinations the FERC will make with respect to these proceedings or what impact, if any, those determinations might have on our ability to establish transportation rates that would allow us to recover the full cost, including a reasonable return, of operating our transportation facilities and that portion of our storage capacity used in support of transportation services. Accordingly, we cannot predict what impact, if any, such determinations could have on our consolidated financial position, results of operations or cash flows.
Our natural gas transportation, storage and gathering operations are subject to regulation by agencies in Oklahoma and Texas, and that regulation could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our facilities, including a reasonable return, and our consolidated financial position, results of operations or cash flows.
State regulation of natural gas transportation, storage and gathering facilities generally focuses on various safety, environmental and, in some circumstances, nondiscriminatory access requirements and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations also are or may become subject to safety and operational regulations relating to the integrity, design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. Any such state regulation could have an adverse impact on our business and our consolidated financial position, results of operations or cash flows.
We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the U.S. Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines. The regulations require operators to:
| ● | identify potential threats to the public or environment, including “high consequence areas” on covered pipeline segments where a leak or rupture could do the most harm; |
| ● | develop a baseline plan to prioritize the assessment of a covered pipeline segment; |
| ● | gather data and identify and characterize applicable threats that could impact a covered pipeline segment; |
| ● | discover, evaluate and remediate problems in accordance with the program requirements; |
| ● | continuously improve all elements of the integrity program; |
| ● | continuously perform preventative and mitigation actions; |
| ● | maintain a quality assurance process and management-of-change process; and |
| ● | establish a communication plan that addresses safety concerns raised by the DOT and state agencies, including the periodic submission of performance documents to the DOT. |
During 2008 and the nine months ended September 30, 2009, we incurred approximately $7.9 million and $9.4 million, respectively, of capital expenditures and operating costs to implement our pipeline integrity management program along certain segments of our natural gas pipelines. We currently estimate that we will incur capital expenditures and operating costs of approximately $39.9 million between 2009 and 2013 in connection with our pipeline integrity management program. The estimated capital expenditures and operating costs include our estimates for the assessment, remediation, prevention or other mitigation that may be determined to be necessary as a result of the integrity management program. At this time, we cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. We will continue our pipeline integrity program to assess, remediate and maintain the integrity of our pipelines. The results of these activities could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.
Events that are beyond our control have increased the level of public and regulatory scrutiny of our industry. Governmental and market reactions to these events may have negative impacts on our business, consolidated financial position, cash flows and access to capital.
As a result of accounting irregularities at public companies in general, and energy companies in particular, and investigations by governmental authorities into energy trading activities, public companies have been under an increased amount of public and regulatory scrutiny and suspicion. The accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies
and their independent auditors. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws and accounting standards, but it is difficult or impossible to predict or control what effect these types of events may have on our business, consolidated financial position, cash flows or access to the capital markets. It is unclear what additional laws or regulations may develop, and we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically. Any new accounting standards could affect the way we are required to record revenues, expenses, assets, liabilities and equity. These changes in accounting standards could lead to negative impacts on reported earnings or decreases in assets or increases in liabilities that could, in turn, affect our results of operations and cash flows.
Operational Risks
Economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also could affect the cost of capital and our ability to raise capital.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which could impact the ability of our customers to pay timely, increase customer bankruptcies, and could lead to increased bad debt. If such circumstances occur, we expect that producer customers would be impacted first, with industrial customers following.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our consolidated financial position, results of operations and cash flows.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the natural gas midstream industry in general, and on us in particular, cannot be known. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of supplies and markets for our products, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than existing insurance coverage.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies sometimes for a specific period of time. A loss of these rights, through our inability to renew right-of-way contracts or otherwise, could cause us to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, reduce our revenue and impair our cash flows.
Natural gas and natural gas liquids (“NGLs”) prices are volatile, and changes in these prices could adversely affect our results of operations and cash flows.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. Our results of operations and cash flows could be adversely affected by volatility in the prices of natural gas and NGLs. Our gathering and processing margins generally improve when NGLs prices are high relative to the price of natural gas. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. With respect to natural gas, the mid-continent prices for natural gas, as represented by the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract in 2006 ranged from a high of $8.76 per million British thermal unit (“MMBtu”) to a low of $3.54 per MMBtu. In 2007, the same index ranged from a high of $6.82 per MMBtu to a low of $4.73 per MMBtu. In 2008, the same index ranged from a high of $11.07 per MMBtu to a low of $2.81 per MMBtu. During the nine months ended September 30, 2009, the same index ranged from a high of $4.57 per MMBtu to a low of $2.46 per MMBtu. Natural gas prices reached relatively high levels in mid-2008 due to the impact of rising demand for natural gas but have returned to the near $2.50 per MMBtu level due to a rapid decline in demand for natural gas. With respect to NGLs, the mid-continent prices for propane, for example, as represented by the average of the Oil Price Information Service daily average posting at the Conway, Kansas market, in 2007 ranged from a high of $1.52 per gallon to a low of $0.87 per gallon. In 2008, the same index ranged from a high of $1.76 per gallon to a low of $0.70 per gallon. During the nine months ended September 30, 2009, the same index ranged from a high of $0.84 per gallon to a low of $0.63 per gallon. Our future revenue and cash flows may be materially adversely affected if the midstream industry experiences significant, prolonged deterioration below general price levels experienced in recent years.
Factors that affect prices of natural gas and NGLs are beyond our control and changes in these prices could adversely affect our revenue and cash flows.
The markets and prices for natural gas and NGLs depend upon factors beyond our control and changes in these prices could adversely affect our revenue and cash flows. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, liquefied natural gas and NGLs, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation
efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.
Our “keep-whole” natural gas processing arrangements and “percent-of-proceeds” and “percent-of-liquids” natural gas processing agreements expose us to risks associated with fluctuations associated with the price of natural gas and NGLs, which could adversely affect our revenue and cash flows.
Our keep-whole natural gas processing arrangements, which constituted approximately 23 percent of our gross margin and accounted for approximately 54 percent of our natural gas processed volumes during 2008 and which constituted approximately four percent of our gross margin and accounted for approximately 34 percent of our natural gas processed volumes during the nine months ended September 30, 2009, expose us to fluctuations in the pricing spreads between NGLs prices and natural gas prices. Keep-whole processing arrangements generally require a processor of natural gas to keep its shippers whole on a British thermal unit (“Btu”) basis by replacing the Btu’s of the NGLs extracted from the production stream with Btu’s of natural gas. Therefore, if natural gas prices increase and NGLs prices do not increase by a corresponding amount, the processor has to replace the Btu’s of natural gas at higher prices and processing margins are negatively affected.
Our percent-of-proceeds and percent-of-liquids natural gas processing agreements constituted approximately nine percent of our gross margin and accounted for approximately 36 percent of our natural gas processed volumes during 2008. Our percent-of-proceeds and percent-of-liquids natural gas processing agreements constituted approximately seven percent of our gross margin and accounted for approximately 47 percent of our natural gas processed volumes during the nine months ended September 30, 2009. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which we share in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which we receive proceeds from the sale of NGLs or the NGLs themselves as compensation for our processing services as percent-of liquids arrangements. These arrangements expose us to risks associated with the price of natural gas and NGLs.
At any given time, our overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that we were a net buyer of natural gas) and a net long position in NGLs (meaning that we were a net seller of NGLs). As a result, our margins could be negatively impacted to the extent the price of NGLs decreases in relation to the price of natural gas.
Because of the natural decline in production from existing wells connected to our systems, our success depends on our ability to gather new sources of natural gas, which depends on certain factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and results of operations and cash flows.
Our gathering and transportation systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering and transportation systems and the asset utilization rates at our natural gas processing plants, we must continually obtain new natural gas supplies. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets depends in part on the level of successful drilling activity near these systems, our ability to compete for volumes from successful new wells and our ability to expand capacity as needed. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our gathering, processing and transportation facilities would decline, which could have a material adverse effect on our business, results of operations and cash flows.
Our businesses are dependent, in part, on the drilling decisions of others.
All of our businesses are dependent on the continued availability of natural gas production. We do not have control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. The primary factor that impacts drilling decisions is natural gas prices. Natural gas prices reached relatively high levels in mid-2008 due to the impact of rising demand for natural gas but have returned to the near $2.50 per MMBtu level due to a rapid decline in demand for natural gas. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering, processing and transportation facilities, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, access to credit, the ability of producers to obtain necessary drilling and other governmental permits, costs of steel and other commodities, geological considerations, demand for hydrocarbons, the level of reserves, other production and development costs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves.
We engage in commodity hedging activities to minimize the impact of commodity price risk, which may have a volatile effect on our earnings and cash flows.
We are exposed to changes in commodity prices in our operations. To minimize the risk of commodity prices, we may enter into physical forward sales or financial derivative contracts to hedge purchase and sale commitments, fuel requirements, contractual length obligations, keep-whole positions, percent-of-liquids positions and inventories of natural gas. However, financial derivative contracts do not eliminate the risk of market supply shortages, which could result in our inability to fulfill contractual obligations and incurrence of significantly higher energy costs relative to corresponding sales contracts. We mark our derivative contracts to estimated fair market value. When available, market prices are utilized in determining the value of natural gas and related derivative commodity instruments.
We engage in cash flow hedge transactions to manage commodity risk. Hedges of anticipated transactions are documented as cash flow hedges and are executed based upon management-established price targets. We apply hedge accounting to account for hedges of contractual length and storage natural gas, percent-of-liquids and keep-whole natural gas and
NGLs hedges. Hedges are evaluated prior to execution with respect to the impact on the volatility of forecasted earnings and are evaluated at least quarterly after execution for the impact on earnings. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.
As a result of the factors discussed above, our hedging activities may not be as effective as intended in reducing the volatility of our cash flows. In addition, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective or the hedging policies and procedures are not properly followed or do not work as planned. The steps taken to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Our results of operations and cash flows may be adversely affected by risks associated with our hedging activities.
We have instituted a hedging program that is intended to reduce the commodity price risk associated with our keep-whole and percent-of-liquids arrangements. As of September 30, 2009, we had hedged approximately 74 percent of our expected non-ethane NGLs volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes, for 2009 through 2011, including approximately 79 percent for 2009, 77 percent for 2010 and 70 percent for 2011. As of September 30, 2009, we had not hedged any of our expected ethane volumes attributable to these arrangements, along with the natural gas MMBtu equivalent for keep-whole volumes. We have the option to reject ethane if processing it is not economical. Management will continue to evaluate whether to enter into any new hedging arrangements, and there can be no assurance that we will enter into any new hedging arrangements. Also, we may seek in the future to further limit our exposure to changes in natural gas and NGLs commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms. To the extent we hedge our commodity price and interest rate exposures, we may forego the benefits that otherwise would be experienced if commodity prices or interest rates were to change in our favor. In addition, even though management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or the hedging policies and procedures are not followed or do not work as planned.
We depend on certain key natural gas producer customers for a significant portion of our supply of natural gas and NGLs. The loss of, or reduction in volumes from, any of these customers could result in a decline in our consolidated financial position, results of operations or cash flows.
We rely on certain key natural gas producer customers for a significant portion of our natural gas and NGLs supply. During 2008, Chesapeake Energy Marketing Inc., Apache Corporation, Devon Gas Services, L.P., Samson Resources Company and Cimarex Energy Co. accounted for approximately 52 percent of our natural gas and NGLs supply. During the nine months ended September 30, 2009, Chesapeake Energy Marketing Inc., Devon Gas Services, L.P., Apache Corporation, Samson Resources Company and BP America Production Company accounted for approximately 52 percent of our natural gas and NGLs supply. The loss of the natural gas and NGLs volumes supplied by these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
We depend on two customers for a significant portion of our firm intrastate transportation and storage services. The loss of, or reduction in volumes from, either of these customers could result in a decline in our transportation and storage services and our consolidated financial position, results of operations or cash flows.
We provide firm intrastate transportation and storage services to several customers on our system. Our major customers are Oklahoma Gas and Electric Company (“OG&E”), the largest electric utility in Oklahoma and a wholly-owned subsidiary of our parent, OGE Energy, and Public Service Company of Oklahoma (“PSO”), which is the second-largest electric utility in Oklahoma and serves the Tulsa market. As part of the no-notice load following contract with OG&E, we provide natural gas storage services for OG&E. We provide gas transmission delivery services to all of PSO’s natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. During 2006, 2007, 2008 and the nine months ended September 30, 2009, revenues from our firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million, $104.4 million and $87.6 million, respectively, of which $47.6 million, $47.4 million, $47.5 million and $35.6 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million, $15.3 million and $12.6 million, respectively, was attributed to PSO. Our current contract with PSO expires January 1, 2013, unless extended. The stated term of our current contract with OG&E expired April 30, 2009, but the contract will remain in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2010, the contract will remain in effect at least through April 30, 2011. The loss of all or even a portion of the intrastate transportation and storage services for either of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
We may not be successful in balancing our purchases and sales of natural gas and NGLs, which would increase our exposure to commodity price risk.
In the normal course of business, we purchase or retain from producers and other customers some of the natural gas and NGLs that flow through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risk and we could have increased volatility in our operating income and cash flows.
If third-party pipelines and other facilities interconnected to our gathering, processing or transportation facilities become partially or fully unavailable, our revenues and cash flows could be adversely affected.
We depend upon third-party natural gas pipelines to deliver gas to, and take gas from, our transportation system. We also depend on third-party facilities to transport and fractionate NGLs that we deliver to the third party at the tailgates of our processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. Since we do not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines or other facilities become partially or fully unavailable, our revenues and cash flows could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our consolidated financial position, results of operations or cash flows.
We compete with similar enterprises in our respective areas of operation. Some of these competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we have. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing, transportation and storage systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and customers. All of these competitive pressures could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.
Gathering, processing, transporting and storing natural gas involves many hazards and operational risks, including:
| ● | damage to pipelines and plants, related equipment and surrounding properties caused by tornadoes, floods, earthquakes, fires and other natural disasters and acts of terrorism; |
| inadvertent damage from third parties, including construction, farm and utility equipment; |
| leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and |
These and other risks could result in substantial losses due to personal injury and loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our insurance is currently provided under OGE Energy’s insurance programs. We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur, which may include toxic tort claims. In addition, we may not be able to maintain or obtain insurance of the type and amount desired at reasonable rates. Moreover, in some instances, significant claims by OGE Energy may limit or eliminate the amount of insurance proceeds available to us. As a result of market conditions, premiums and deductibles for certain of OGE Energy’s insurance policies have increased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial results.
Financial Risks
Market performance, increased retirements, changes in retirement plan regulations and increasing costs associated with OGE Energy’s defined benefit retirement plans, health care plans and other employee-related benefits may adversely affect our results of operations, consolidated financial position, or liquidity.
OGE Energy has defined benefit retirement and postretirement plans that cover substantially all of our employees. OGE Energy’s assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions with respect to the defined benefit retirement and postretirement plans have a significant impact on our earnings and funding requirements. Based on OGE Energy’s assumptions at December 31, 2008, OGE Energy expects to continue to make future contributions, of which a portion would be attributed to us, to maintain required funding levels; however, as OGE Energy’s plans have experienced adverse market returns on investments in 2008 due to the market turmoil in the financial markets experienced in late 2008 and early 2009, this could cause OGE Energy’s future contributions, of which a portion would be attributed to us, to rise substantially over historical levels. It is OGE Energy’s practice to also make voluntary contributions to maintain more prudent funding levels than minimally required. These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.
On August 17, 2006, former President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions, introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants.
Many of the changes enacted as part of the Pension Protection Act were required to be implemented as of the first plan year beginning in 2008. While the Company generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. See Note 11 of Notes to the Consolidated Financial Statements for the year ended December 31, 2008 for a further discussion of changes made to the Company’s plans in order to comply with the Pension Protection Act.
All employees hired prior to February 1, 2000 participate in OGE Energy’s defined benefit and postretirement plans. If these employees retire when they become eligible for retirement over the next several years, or if OGE Energy’s plan experiences adverse market returns on its investments, or if interest rates materially fall, our pension expense and contributions to the plans could rise substantially over historical levels. A portion of OGE Energy’s pension expense and contributions is expected to be allocated to us. The timing and number of employees retiring and selecting the lump-sum payment option could result in pension settlement charges that could materially affect our results of operations. In addition, assumptions related to future costs, returns on investments, interest rates and other actuarial assumptions, including projected retirements, have a significant impact on our results of operations and consolidated financial position. Those factors are outside of our control.
In addition to the costs of OGE Energy’s retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements with our defined benefit retirement plan, health care plans and other employee benefits may adversely affect our results of operations, consolidated financial position, or liquidity.
We face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements.
Workforce demographic issues challenge employers nationwide and are of particular concern to the natural gas pipeline industry. The median age of natural gas pipeline workers is significantly higher than the national average. Over the next three years, approximately 13 percent of our current employees will be eligible to retire with full pension benefits. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business.
We and our subsidiaries may be able to incur substantially more indebtedness, which may increase the risks created by our indebtedness.
The terms of the Issuing and Paying Agency Agreement and the instruments governing our other debt securities do not fully prohibit us or our subsidiaries from incurring additional indebtedness. If we or our subsidiaries are in compliance with the financial covenants set forth in our revolving credit agreement, we and our subsidiaries may be able to incur substantial additional indebtedness. If we or any of our subsidiaries incur additional indebtedness, the related risks that we and they now face may intensify.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships or limit our ability to obtain financing on favorable terms.
We cannot assure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. The ability of OGE Energy to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruption as experienced with the market turmoil experienced in late 2008 and early 2009. Pricing grids associated with our credit facility could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade would also lead to higher long-term borrowing costs and, if below investment grade, would require us to post cash collateral or letters of credit.
Any negative change in OERI’s creditworthiness could adversely affect our ability to engage in hedging transactions or adversely affect the prices and terms upon which hedging transactions occur.
We historically have conducted our hedging activities with OERI, our former subsidiary which is now a wholly-owned subsidiary of OGE Energy, as our counterparty. OERI, in turn, has engaged in back-to-back hedging transactions with third parties. The willingness of those third parties to serve as counterparties on OERI’s hedging transactions depends on OERI’s creditworthiness. Any negative change in OERI’s creditworthiness could adversely affect OERI’s and our ability to enter into hedging transactions, or the prices and terms upon which such transactions may be effected.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We have a revolving credit agreement for working capital, capital expenditures, including acquisitions, and other corporate purposes. The levels of our debt could have important consequences, including the following:
| the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms; |
| a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations and future business opportunities; and |
| our debt levels may limit our flexibility in responding to changing business and economic conditions. |
We are exposed to the credit risk of our key customers and counterparties, and any material nonpayment or nonperformance by our key customers and counterparties could adversely affect our consolidated financial position, results of operations and cash flows.
We are exposed to credit risks in our pipeline operations. Credit risk includes the risk that customers and counterparties that owe us money or energy will breach their obligations. If such parties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected, and we could incur losses.
ENOGEX LLC
Overview
Enogex and its subsidiaries are providers of integrated natural gas midstream services. Most of our natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Our operations are organized into two business segments: (1) natural gas transportation and storage and (2) natural gas gathering and processing. We are a wholly-owned subsidiary of OGE Energy.
Prior to January 1, 2008, we had engaged in natural gas marketing through our former subsidiary, OERI. On January 1, 2008, we distributed the stock of OERI to OGE Energy. Accordingly, our operations no longer include OERI’s marketing of natural gas.
We were organized on April 1, 2008, when Enogex Inc., our predecessor company, converted from an Oklahoma corporation to a Delaware limited liability company. Our principal executive offices are located at 515 Central Park Drive, Suite 110, Oklahoma City, Oklahoma 73105, and our telephone number is (405) 525-7788. Our Internet address is http://www.enogex.com. Our Internet address is provided for informational purposes only. No information or materials contained at such website are to be considered as part of this offering memorandum.
Effective July 1, 2009, Enogex LLC formed a new entity, Enogex Gathering & Processing LLC, for purposes of holding the membership interests of Enogex Gas Gathering LLC, Enogex Products LLC and Enogex Atoka LLC, which were previously direct wholly owned subsidiaries of Enogex LLC.
Our Relationship with OGE Energy
One of our principal strengths is our relationship with OGE Energy, our corporate parent. Since our inception, we have been the transporter of natural gas to OG&E’s natural gas-fired electric generation facilities. Our current contract with OG&E provides for no-notice load following transportation and storage services. For the years ended December 31, 2006, 2007, 2008 and for the nine months ended September 30, 2009, revenues attributed to OG&E were approximately $47.6 million, $47.4 million, $47.5 million and $35.6 million, respectively, under the contract. We believe we benefit from a higher credit rating due to our relationship with OGE Energy.
As indicated above, on January 1, 2008, we distributed the stock of OERI to OGE Energy. We have historically utilized, and expect to continue to utilize, OERI for natural gas marketing, hedging, risk management and other related activities. For the years ended December 31, 2006, 2007, 2008 and for the nine months ended September 30, 2009, we recorded expenses from OERI of approximately $107.1 million, $95.2 million, $41.9 million and $37.3 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2006, 2007, 2008 and for the nine months ended September 30, 2009, we recorded revenues from OERI of approximately $291.9 million, $304.3 million, $307.2 million and $118.7 million, respectively, for the sale, at market rates, of natural gas.
Selected Financial Information
The following table sets forth selected consolidated financial information for the Company and its subsidiaries as of and for each of the five years in the period ended December 31, 2008 (extracted from the Company’s audited consolidated financial statements and accounting records for such periods) and as of and for the nine months ended September 30, 2009 and September 30, 2008. The information set forth in the following table should be read in conjunction with (1) the Company’s Annual Report for the year ended December 31, 2008, which includes audited consolidated financial statements and a discussion of results of operations for certain of the periods shown below, attached hereto as Exhibit A, (2) the Company’s unaudited condensed consolidated financial statements for the nine months ended September 30, 2009 and September 30, 2008 attached hereto as Exhibit B and (3) the Company’s Management’s Discussion and Analysis attached hereto as Exhibit C.
Effective January 1, 2009, we adopted a new accounting standard which changed the presentation of the noncontrolling interest in our consolidated financial statements for our 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”). The results of operations data for the nine months ended September 30, 2008 have been adjusted to reflect this change; however, the results of operations data for the five years ended December 31, 2008 and the balance sheet data at December 31, 2008, 2007, 2006, 2005 and 2004 have not been adjusted for this change in order to be consistent with our previously audited consolidated financial statements.
Selected Financial Information
(Dollars in millions)
| | | Nine Months Ended September 30, | | | | |
| | | | | | | | | | 2008 (A) | | | | 2007 | | | | 2006 | | | | 2005 | | | | 2004 | |
| Selected Financial Data | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Results of Operations Data | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 591.7 | | | $ | 911.1 | | | $ | 1,103.2 | | | $ | 2,065.2 | | | $ | 2,367.8 | | | $ | 4,340.1 | | | $ | 3,372.2 | |
| Cost of goods sold | | | 330.4 | | | | 595.8 | | | | 710.2 | | | | 1,712.1 | | | | 2,060.4 | | | | 4,090.4 | | | | 3,118.2 | |
| Gross margin on revenues | | | 261.3 | | | | 315.3 | | | | 393.0 | | | | 353.1 | | | | 307.4 | | | | 249.7 | | | | 254.0 | |
| Other operating expenses | | | 155.0 | | | | 154.5 | | | | 207.8 | | | | 189.6 | | | | 168.6 | | | | 152.4 | | | | 158.4 | |
| Operating income | | | 106.3 | | | | 160.8 | | | | 185.2 | | | | 163.5 | | | | 138.8 | | | | 97.3 | | | | 95.6 | |
| Interest income | | | 0.1 | | | | 2.2 | | | | 2.5 | | | | 9.2 | | | | 11.1 | | | | 2.9 | | | | 3.2 | |
| Other income | | | 0.1 | | | | 1.0 | | | | 1.0 | | | | 0.9 | | | | 7.7 | | | | 0.8 | | | | 4.5 | |
| Other expense | | | 0.5 | | | | 0.6 | | | | 1.4 | | | | 1.3 | | | | 0.3 | | | | 0.3 | | | | 0.3 | |
| Minority interest | | | — | | | | — | | | | 6.1 | | | | 1.0 | | | | — | | | | — | | | | — | |
| Interest expense | | | 24.4 | | | | 24.8 | | | | 32.7 | | | | 31.6 | | | | 31.8 | | | | 32.6 | | | | 32.2 | |
| Income tax expense | | | 30.2 | | | | 51.7 | | | | 57.3 | | | | 53.5 | | | | 48.0 | | | | 23.4 | | | | 26.4 | |
| Income from continuing | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| operations | | | 51.4 | | | | 86.9 | | | | 91.2 | | | | 86.2 | | | | 77.5 | | | | 44.7 | | | | 44.4 | |
| Income from discontinued | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| operations, net of tax | | | — | | | | — | | | | — | | | | — | | | | 36.0 | | | | 49.8 | | | | 11.6 | |
| Net income | | | 51.4 | | | | 86.9 | | | | 91.2 | | | | 86.2 | | | | 113.5 | | | | 94.5 | | | | 56.0 | |
| Less: Net income | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| attributable to | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| noncontrolling interest | | | 1.9 | | | | 5.2 | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Net Income Attributable to | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Enogex LLC | | $ | 49.5 | | | $ | 81.7 | | | $ | 91.2 | | | $ | 86.2 | | | $ | 113.5 | | | $ | 94.5 | | | $ | 56.0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Data (at period | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| end) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Property, plant and equipment, | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| net (B) | | $ | 1,391.6 | | | $ | 1,151.1 | | | $ | 1,261.4 | | | $ | 985.1 | | | $ | 865.7 | | | $ | 875.9 | | | $ | 1,016.5 | |
| Total assets | | | 1,539.6 | | | | 1,330.6 | | | | 1,458.3 | | | | 1,356.8 | | | | 1,319.8 | | | | 1,652.6 | | | | 1,719.7 | |
| Long-term debt (C)(D) | | | 579.0 | | | | 521.2 | | | | 520.9 | | | | 402.8 | | | | 406.7 | | | | 407.6 | | | | 512.1 | |
| Total stockholder’s equity (E) | | | — | | | | — | | | | — | | | | 378.9 | | | | 400.0 | | | | 440.4 | | | | 491.0 | |
| Total member’s interest (E) | | | 462.1 | | | | 326.4 | | | | 379.7 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capitalization Ratios (at period end) (F) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Stockholder’s equity | | | N/A | | | | N/A | | | | N/A | | | | 48.5 | % | | | 49.6 | % | | | 51.9 | % | | | 48.9 | % |
| Member’s interest | | | 44.4 | % | | | 38.5 | % | | | 42.2 | % | | | N/A | | | | N/A | | | | N/A | | | | N/A | |
| Long-term debt | | | 55.6 | % | | | 61.5 | % | | | 57.8 | % | | | 51.5 | % | | | 50.4 | % | | | 48.1 | % | | | 51.1 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ratio of Earnings to Fixed Charges (G) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Ratio of earnings to fixed | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| charges | | | 3.38 | | | | 5.82 | | | | 4.96 | | | | 5.24 | | | | 4.77 | | | | 3.06 | | | | 3.17 | |
| (A) | On January 1, 2008, we distributed the stock of OERI to OGE Energy, and as a result, OERI is no longer our subsidiary and its results of operations are not included for any period subsequent to December 31, 2007. |
| (B) | Includes net property, plant and equipment related to discontinued operations of approximately $169.3 million and $34.9 million during the years ended December 31, 2004 and 2005, respectively. |
| (C) | Includes long-term debt due within one year. |
| (D) | Includes long-term debt related to discontinued operations of approximately $65.0 million during the year ended December 31, 2004. |
| (E) | Effective April 1, 2008, Enogex Inc. converted from an Oklahoma corporation to a Delaware limited liability company which resulted in the conversion of common stock to member’s interest as of April 1, 2008. |
| (F) | Capitalization ratios = [Total Stockholders’ equity or Member’s interest / (Total Stockholders’ equity or Member’s interest + Long-term debt + Long-term debt due within one year)] and [(Long-term debt + Long-term debt due within one year) / (Total Stockholders’ equity or Member’s interest + Long-term debt + Long-term debt due within one year)]. |
| (G) | For purposes of computing the ratio of earnings to fixed charges, (1) earnings consist of pre-tax income from continuing operations plus fixed charges less capitalized interest; and (2) fixed charges consist of interest on long-term debt, related amortization, interest on short-term borrowings and a calculated portion of rents considered to be interest. In addition, for the nine months ended September 30, 2009 and 2008, the noncontrolling interest related to the Atoka joint venture was removed from pre-tax income from continuing operations. |
Transportation and Storage
General
Our transportation and storage business owns and operates approximately 2,433 miles of intrastate natural gas transportation pipelines with approximately 1.80 trillion British thermal units per day (“TBtu/d”) of average daily throughput during the nine months ended September 30, 2009. We also own and operate two storage facilities currently being operated at a working gas level of approximately 24 billion cubic feet (“Bcf”). We provide fee-based intrastate transportation services on a firm and interruptible basis and, pursuant to Section 311 of the NGPA, provide interstate transportation services on an interruptible basis. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified demand or reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a transportation or commodity charge with respect to quantities actually transported by us. Our obligation to provide interruptible transportation service means that we are obligated to transport natural gas nominated by the shipper only to the extent that we have available capacity. For this service, the shipper pays no demand or reservation charge but pays a transportation or commodity charge for quantities actually shipped. We derive a substantial portion of our transportation revenues from firm transportation services. To the extent pipeline capacity is not needed for such firm intrastate transportation service, we offer interruptible interstate transportation services pursuant to Section 311 of the NGPA as well as interruptible intrastate transportation services.
Customers and Contracts
Our major transportation customers are our affiliate, OG&E, the largest electric utility in Oklahoma, and PSO, the second-largest electric utility in Oklahoma. We provide gas transmission delivery services to all of PSO’s natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract and the OG&E contract provide for a monthly demand charge plus variable transportation charges (including fuel). The PSO contract expires January 1, 2013, unless extended. The stated term of the OG&E contract expired April 30, 2009, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to May 1, 2010, the contract will remain in effect at least through April 30, 2011. As part of the no-notice load following contract with OG&E, we provide natural gas storage services for OG&E. We have been providing natural gas storage services to OG&E since August 2002 when we acquired the Stuart Storage Facility. Demand for natural gas on our system is usually greater during the summer, primarily due to demand by gas-fired electric generation facilities to serve residential and commercial electricity requirements. Natural gas produced in excess of that which is used during the winter months is typically stored to meet the increased demand for natural gas during the summer months. During 2006, 2007, 2008 and the nine months ended September 30, 2009, revenues from our firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million, $104.4 million and $87.6 million, respectively, of which approximately $47.6 million, $47.4 million, $47.5 million and $35.6 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million, $15.3 million and $12.6 million, respectively, was attributed to PSO. Revenues from our firm intrastate transportation and storage contracts represented approximately 31 percent of our consolidated gross margin on revenues (“gross margin”) in 2006, 29 percent in 2007, 27 percent in 2008 and 34 percent for the nine months ended September 30, 2009.
Regulation
Our pipeline operations are subject to various state and federal safety and environmental and pipeline transportation laws. For example, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines. During 2008 and the nine months ended September 30, 2009, we incurred approximately $7.9 million and $9.4 million, respectively, of capital expenditures and operating costs to implement our pipeline integrity management program along certain segments of our natural gas pipelines. We currently estimate that we will incur capital expenditures and operating costs of approximately $39.9 million between 2009 and 2013 in connection with our pipeline integrity management program. The estimated capital expenditures and operating costs include our estimates for the assessment, remediation and prevention or other mitigation that may be determined to be necessary as a result of the integrity management program. At this time, we cannot predict the ultimate costs of compliance with this regulation because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity assessment that is required by the rule. We will continue our pipeline integrity program
to assess, remediate and maintain the integrity of our pipelines. The results of these activities could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.
Recent System Expansions
Over the past several years, we have initiated multiple organic growth projects. Currently, in our transportation and storage business, organic growth capital expenditures are focused on upgrades to our existing transportation system due to increased volumes as a result of the broader shift of gas flow from the Rocky Mountains and the mid-continent to markets in the northeast and southeast United States.
In December 2006, we entered into a firm capacity lease agreement with Midcontinent Express Pipeline, LLC (“MEP”) for a primary term of ten years (subject to possible extension) that gives MEP and its shippers access to capacity on our system. The quantity of capacity subject to the MEP lease agreement is currently 272 million cubic feet per day (“MMcf/d”), with the quantity ultimately to be leased subject to being increased by mutual agreement pursuant to the lease agreement. In addition to MEP’s lease of our capacity, the MEP project included construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. Our capital expenditures related to this project were approximately $99 million.
On July 25, 2008, the FERC issued its order approving the MEP project including the approval of a limited jurisdiction certificate authorizing our lease agreement with MEP. Further, the FERC order rejected all claims raised by protestors regarding the lease agreement. Accordingly, we proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, one protestor filed a request for rehearing. The FERC denied the request for rehearing, and we commenced service to MEP under the lease agreement on June 1, 2009. On July 16, 2009, the protestor filed a petition for review of the FERC’s orders before the United States Court of Appeals for the District of Columbia Circuit requesting that the orders be modified or set aside on the grounds that they are arbitrary, capricious and contrary to law. The petitioner, the FERC and interested parties that have sought intervenor status will be given an opportunity to brief the issues. We have filed our intervention and expect to participate in the filing of a joint intervenors’ brief in support of the FERC’s order in this matter. On October 27, 2009, the Court of Appeals issued an order establishing the briefing schedule for the proceeding which provides for the briefing to be completed in the first quarter of 2010. On November 2, 2009, the Court of Appeals issued an order extending the briefing schedule for the proceeding which provides for the briefing to be completed in the second quarter of 2010.
Gathering and Processing
General
Our gathering system includes approximately 5,763 miles of natural gas gathering pipelines with approximately 1.25 TBtu/d of average daily throughput during the nine months ended September 30, 2009 extending from southwestern Oklahoma to the eastern Texas Panhandle. During 2008, we connected 357 new producing wells (including 154 wells behind
central receipt points), located in the Arkoma and Anadarko basins (including recent growth activity in the Granite Wash play in western Oklahoma and the Texas Panhandle and the Woodford Shale play in southeastern Oklahoma) to our gathering systems. At December 31, 2008, our gathering system was connected to approximately 3,278 wells and approximately 266 central receipt points, all of which are equipped with state-of-the-art electronic flow measurement technology. Approximately 74 percent of our gathered volumes are received at wellheads while 26 percent is gathered from central receipt or other interconnection points.
We completed construction of a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant is processing new gas developing in the area and was placed in service in late October 2009. In support of this plant, we have installed approximately 15 miles of gathering pipe, 2.5 miles of transmission pipe and 10,000 horsepower of inlet compression, as well as other system upgrades. The capital expenditures associated with these projects were approximately $76 million.
We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” and “percent-of-liquids” arrangements and “keep-whole” arrangements. Percent-of-proceeds, percent-of-liquids and keep-whole arrangements involve commodity price risk to us because our margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts.
| Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our system and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. At December 31, 2008, these arrangements accounted for approximately ten percent of our natural gas processed volumes. At September 30, 2009, these arrangements accounted for approximately 19 percent of our natural gas processed volumes. |
| Percent-of-Proceeds and Percent-of-Liquids Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. The price paid to producers is based on an agreed percentage of the proceeds of the sale of processed natural gas, NGLs or both or the expected proceeds based on an index price. We refer to contracts in which we share in specified percentages of the proceeds from the sale of natural gas and NGLs as percent-of-proceeds arrangements and in which we receive proceeds from the sale of NGLs or the NGLs |
| | themselves as compensation for our processing services as percent-of-liquids arrangements. Under percent-of-proceeds arrangements, our margin correlates directly with the prices of natural gas and NGLs. Under percent-of-liquids arrangements, our margin correlates directly with the prices of NGLs. At December 31, 2008, these arrangements accounted for approximately 36 percent of our natural gas processed volumes. At September 30, 2009, these arrangements accounted for approximately 47 percent of our natural gas processed volumes. |
| Keep-Whole Arrangements. We process raw natural gas to extract NGLs and return to the producer the full gas equivalent Btu value of raw natural gas received from the producer in the form of either processed gas or its cash equivalent. We are entitled to retain the processed NGLs and to sell them for our own account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including conditioning floors (such as the default processing fee described below) that allow the keep-whole contract to be charged a fee if the NGLs have a lower value than their gas equivalent Btu value in natural gas. At December 31, 2008, these arrangements accounted for approximately 54 percent of our natural gas processed volumes. At September 30, 2009, these arrangements accounted for approximately 34 percent of our natural gas processed volumes. |
Customers and Contracts
Residue gas remaining after processing is primarily taken in kind by the producer customers into our transportation pipelines for redelivery either (1) to on-system customers such as the electric generation facilities of OG&E, PSO and other independent power producers or (2) into downstream interstate pipelines. Our NGLs are typically sold to NGL marketers and end users, our condensate liquid production is typically sold to marketers and refineries and our propane is typically sold in the local market to wholesale distributors. Our key natural gas producer customers in 2008 included Chesapeake Energy Marketing Inc., Apache Corporation, Devon Gas Services, L.P., Samson Resources Company and Cimarex Energy Co. During 2008, these five customers accounted for approximately 20 percent, 15 percent, nine percent, four percent and three percent, respectively, of our gathering and processing volumes. During 2008, our top ten natural gas producer customers accounted for approximately 65 percent of our gathering and processing volumes. Our key natural gas producer customers during the nine months ended September 30, 2009 included Chesapeake Energy Marketing Inc., Devon Gas Services, L.P., Apache Corporation, Samson Resources Company and BP America Production Company. During the nine months ended September 30, 2009, these five customers accounted for approximately 18 percent, 13 percent, 13 percent, four percent and four percent, respectively,
of our gathering and processing volumes. During the nine months ended September 30, 2009, our top ten natural gas producer customers accounted for approximately 66 percent of our gathering and processing volumes.
Recent System Expansions
We completed construction of a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant is processing new gas developing in the area and was placed in service in late October 2009. In support of this plant, we have installed approximately 15 miles of gathering pipe, 2.5 miles of transmission pipe and 10,000 horsepower of inlet compression, as well as other system upgrades. The capital expenditures associated with these projects were approximately $76 million.
Properties
At December 31, 2008, we and our subsidiaries owned: (1) approximately 5,763 miles of intrastate natural gas gathering pipelines in Oklahoma and Texas; (2) approximately 2,433 miles of intrastate natural gas transportation pipelines in Oklahoma and Texas; (3) two natural gas storage facilities in Oklahoma operating at a working gas level of approximately 24 Bcf with approximately 650 MMcf/d of maximum withdrawal capacity and approximately 650 MMcf/d of injection capacity; and (4) six operating natural gas processing plants, with a total inlet capacity of approximately 723 MMcf/d, a 50 percent interest in an additional natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and two idle natural gas processing plants, all located in Oklahoma. The following table sets forth information with respect to our active natural gas processing plants:
| | | | | 2009 Average Daily | Inlet |
| Processing | Year | | Fuel | Inlet Volumes | Capacity |
| Plant | Installed | Type of Plant | Capability | (MMcf/d) | (MMcf/d) |
Calumet (A) | 1969 | Lean Oil | Gas | 134 | 250 |
Canute (B) | 1996 | Cryogenic | Electric | 57 | 60 |
Cox City (B) | 1994 | Cryogenic | Gas/Electric | 167 | 180 |
Harrah (A) | 1994 | Cryogenic | Gas/Electric | 12 | 38 |
Thomas (A) | 1981 | Cryogenic | Gas | 131 | 135 |
| Wetumka (A) | 1983 | Cryogenic | Gas | 49 | 60 |
Atoka (C) | 2007 | Refrigeration | Electric | 16 | 20 |
| Total | | 566 | 743 |
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| (A) | These processing plants are located on property that Enogex owns in fee. |
| (B) | These processing plants are located on leased rental property. |
| (C) | Atoka was placed into operation in August 2007. The above amount represents Enogex’s 50 percent ownership interest in Atoka. |
We completed construction of a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant is processing new gas developing in the area and was placed in service in late October 2009. In support of this plant, we have installed approximately 15 miles of gathering pipe, 2.5 miles of transmission pipe and 10,000 horsepower of inlet compression, as well as other system upgrades. The capital expenditures associated with these projects were approximately $76 million.
2009 OUTLOOK
In its Quarterly Report on Form 10-Q for the nine months ended September 30, 2009 that it filed with the Securities and Exchange Commission on October 30, 2009, OGE Energy included 2009 earnings guidance that reflected Enogex’s 2009 earnings guidance at $51 million to $68 million.
2010 OUTLOOK
In its Quarterly Report on Form 10-Q for the nine months ended September 30, 2009 that it filed with the Securities and Exchange Commission on October 30, 2009, OGE Energy included 2010 earnings guidance that reflected Enogex’s 2010 earnings guidance at $63 million to $85 million.
LIQUIDITY AND CAPITAL REQUIREMENTS
Enogex’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations and other general corporate purposes. Enogex generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and borrowings from OGE Energy) and permanent financings.
Capital requirements and future contractual obligations estimated for the next five years and beyond are shown below. These capital expenditures represent the base maintenance capital expenditures (i.e. capital expenditures to maintain and operate Enogex’s businesses) plus capital expenditures for known and committed projects (collectively referred to as the “Base Capital Expenditure Plan”). The table below summarizes the capital expenditures by category:
| | | | | | | | | | 2010– | | | | 2012– | | | | | |
| | | | | | | | | | 2011 | | | | 2013 | | | | 2014 | |
| | | (in millions) | |
| Base Maintenance and Known and Committed | | | | | | | | | | | | | | | | | | | | |
| Projects (A) | | $ | 500.0 | | | $ | 229.0 | | | $ | 136.0 | | | $ | 90.0 | | | $ | 45.0 | |
Maturities of long-term debt | | | 579.2 | | | | — | | | | 289.2 | | | | 90.0 | | | | 200.0 | |
Interest payments on long-term debt | | | 113.2 | | | | 32.7 | | | | 39.2 | | | | 27.5 | | | | 13.8 | |
Pension funding obligations | | | 20.0 | | | | — | | | | 10.0 | | | | 10.0 | | | | — | |
Total capital requirements | | | 1,212.4 | | | | 261.7 | | | | 474.4 | | | | 217.5 | | | | 258.8 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating lease obligations | | | | | | | | | | | | | | | | | | | | |
Enogex noncancellable operating leases | | | 8.8 | | | | 4.3 | | | | 4.1 | | | | 0.4 | | | | — | |
Total operating lease obligations | | | 8.8 | | | | 4.3 | | | | 4.1 | | | | 0.4 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Total capital requirements, operating lease obligations and other purchase obligations and commitments | | $ | 1,221.2 | | | $ | 266.0 | | | $ | 478.5 | | | $ | 217.9 | | | $ | 258.8 | |
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| (A) | Enogex’s capital expenditures for 2009 and 2010 include approximately $56 million related to construction of a pipeline and compressor station that Enogex is completing on behalf of a third party in which Enogex will be reimbursed for the capital expenditures. |
2008 Capital Requirements and Financing Activities
Total capital requirements, consisting of capital expenditures, maturities of long-term debt and interest payments on long-term debt, were approximately $365.0 million and contractual obligations were approximately $8.6 million resulting in total capital requirements and contractual obligations of approximately $373.6 million in 2008. Approximately $0.4 million of the 2008 capital requirements were to comply with environmental regulations. This compares to capital requirements of approximately $197.1 million and contractual obligations of approximately $9.7 million totaling approximately $206.8 million in 2007, of which approximately $2.0 million was to comply with environmental regulations. During 2008, Enogex’s sources of capital were cash generated from operations and long-term borrowings. Changes in working capital reflect the seasonal nature of Enogex’s business, the revenue lag between billing and collection from customers and natural gas inventories. See “Financial Condition” for a discussion of significant changes in net working capital requirements as it pertains to operating cash flow and liquidity.
Long-Term Debt Maturities
Maturities of Enogex’s long-term debt during the next five years consist of $289.2 million in 2010, the outstanding balance under Enogex’s revolving credit facility in 2013 and $200.0 million in 2014. At September 30, 2009, there was approximately $90.0 million outstanding under Enogex’s revolving credit facility.
At September 30, 2009, Enogex had approximately $2.3 million of cash and cash equivalents. At September 30, 2009, Enogex had approximately $160.0 million of net available liquidity under its revolving credit agreement.
Cash Flows
| | | Nine Months Ended September 30, | | | | |
| | | | | | | | | | | | | | | | |
| | | (in millions) | |
| Net cash provided from operating activities | | $ | 74.8 | | | $ | 136.8 | | | $ | 242.0 | | | $ | 107.8 | | | $ | 131.6 | |
| Net cash used in investing activities | | | (179.3 | ) | | | (206.1 | ) | | | (331.3 | ) | | | (165.5 | ) | | | (65.1 | ) |
| Net cash provided from (used in) financing | | | | | | | | | | | | | | | | | | | | |
| activities | | | 89.7 | | | | 101.0 | | | | 103.2 | | | | 60.9 | | | | (139.4 | ) |
The decrease of approximately $62.0 million in net cash provided from operating activities during the nine months ended September 30, 2009 as compared to the same period in 2008 was primarily due to a decrease in sales and purchases due to a decrease in natural gas prices and volumes in the first nine months of 2009 as compared to the same period in 2008.
The decrease of approximately $26.8 million in net cash used in investing activities during the nine months ended September 30, 2009 as compared to the same period in 2008 primarily related to higher levels of capital expenditures in 2008 primarily related to various transportation and gathering projects.
The decrease of approximately $11.3 million in net cash provided from financing activities during the nine months ended September 30, 2009 as compared to the same period in 2008 primarily related to:
| increases in advances to OGE Energy during the nine months ended September 30, 2009 as compared to a decrease in advances to OGE Energy during the same period in 2008; |
| the retirement of approximately $110.8 million in long-term debt related to the tender offer discussed below; and |
| lower levels of borrowings and a higher level of repayments under Enogex’s revolving credit agreement during the nine months ended September 30, 2009. |
These decreases in net cash provided from financing activities were partially offset by:
| proceeds received from the issuance of $200 million in long-term debt in June 2009; |
| a member distribution to OGE Energy of $96.0 million during nine months ended September 30, 2008 with no comparable item during the same period in 2009; |
| a capital contribution of $50.0 million from OGE Energy during the nine months ended September 30, 2009 with no comparable item during the same period in 2008; and |
| dividends paid on common stock of $30.0 million during the nine months ended September 30, 2008 with no comparable item during the same period in 2009. |
The increase of approximately $134.2 million in net cash provided from operating activities in 2008 as compared to 2007 was primarily due to: (1) an increase in NGLs and natural gas volumes and prices and (2) an increase in price risk management assets and liabilities due to net cash collateral received related to Enogex’s existing derivative positions. The reduction of approximately $23.8 million in net cash provided from operating activities in 2007 as compared to 2006 was primarily related to an increase in collateral and option premiums payments made by OERI to counterparties.
The increase of approximately $165.8 million in net cash used in investing activities in 2008 as compared to 2007 related to a higher level of capital expenditures. The increase of approximately $100.4 million in net cash used in investing activities in 2007 as compared to 2006 related to higher levels of capital expenditures.
The increase of approximately $42.3 million in net cash provided from financing activities in 2008 as compared to 2007 primarily related to proceeds received from the line of credit primarily related to Enogex capital expenditures and distributions paid to OGE Energy. The increase of approximately $200.3 million in net cash provided from financing activities in 2007 as compared to 2006 primarily related to a decrease in advances to OGE Energy in 2008 and a decrease in common stock repurchases in 2007.
Future Capital Requirements and Financing Activities
Capital Expenditures
Enogex’s current 2009 to 2014 construction program includes continued investment in its transportation, storage, gathering and processing assets. Enogex’s current estimates of capital expenditures are approximately: 2009—$229 million, 2010—$101 million, 2011—$35 million, 2012—$45 million, 2013—$45 million and 2014—$45 million. For 2009, these capital expenditures include expenditures of approximately $49 million related to expansion projects in western Oklahoma, approximately $41 million related to transportation projects, approximately $39 million related to expansion in the Woodford Shale play and approximately $26 million related to expansion projects in the Texas Panhandle. These capital expenditure projections reflect base market conditions at October 31, 2009 and do not reflect the potential opportunity for a set of growth projects that could materialize if natural gas prices rise in the future.
Refinancing of Debt and Tender Offer
On June 24, 2009, Enogex issued $200 million of 6.875% 5-year senior notes in a transaction exempt from the registration requirements of the Securities Act of 1933. Enogex applied a portion of the net proceeds from the sale of the new notes to pay the purchase price in the tender offer discussed below for its 8.125% notes due January 2010 with the remainder of the net proceeds being used to repay a portion of Enogex’s borrowings under its revolving credit agreement and for general corporate purposes. The refinancing of the balance of Enogex’s 8.125% notes due January 2010 is expected to occur later in the fourth quarter of 2009. At this time, Enogex cannot predict how interest rates will affect its ability to obtain financing on favorable terms.
Also on June 24, 2009, Enogex commenced a cash tender offer for up to $150 million principal amount of its 8.125% senior notes due January 2010. The tender offer for the 8.125% senior notes due January 2010 expired on July 22, 2009. The total consideration per $1,000 principal amount of the 8.125% senior notes due January 2010 validly tendered and not withdrawn was $1,027.50. Pursuant to the tender offer, on July 23, 2009, Enogex purchased approximately $110.8 million principal amount of the 8.125% senior notes due January 2010 and those repurchased notes were retired and cancelled.
Future Sources of Financing
Management expects that cash generated from operations or proceeds from the issuance of long and short-term debt or other offerings will be adequate over the next three years to meet anticipated cash needs. Enogex utilizes short-term borrowings (through a combination of bank
borrowings and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.
Short-Term Debt and Revolving Credit Facility
Short-term borrowings generally are used to meet working capital requirements. At September 30, 2009 and December 31, 2008, respectively, Enogex had approximately $90.0 million and $120.0 million outstanding under its revolving credit agreement. The following table shows Enogex’s revolving credit agreement and available cash at September 30, 2009.
| Revolving Credit Agreement and Available Cash | |
| | | | | | | | | Weighted-Average Interest Rate | | | | |
| | | (in millions) | |
Revolving Credit Agreement | | $ | 250.0 | | | $ | 90.0 | | | | 0.57 | % | | March 31, 2013 | |
Cash | | | 2.3 | | | | N/A | | | | N/A | | | | N/A | |
Total | | $ | 252.3 | | | $ | 90.0 | | | | 0.57 | % | | | | |
| | | | | | | | | | | | | | | | | |
