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 of our facilities 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. For example, earlier this year, 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.
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 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. As a recent example, a U.S. Supreme Court decision holding that the EPA relied on improper factors in deciding not to regulate greenhouse gas emissions from motor vehicles as air pollutants covered by the Clean Air Act has resulted in proposed findings by the EPA that greenhouse gas emissions threaten public health and welfare and contribute to the threat of climate change. In addition, the EPA has initiated a proposed rule requiring measuring and reporting of greenhouse gas emissions. If this rule is finalized as proposed, we may incur additional costs to comply with the monitoring, collection and reporting requirements on our affected facilities. The current proposed effective date for gathering the data is January 2010 with the first mandatory reporting date as 2011.
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 transmission 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. We are currently charging rates for our Section 311 transportation services that were deemed fair and equitable under a rate settlement approved by the FERC for the period from January 1, 2005 until December 31, 2007. On October 1, 2007, we made our required triennial rate filing at the FERC to update our Section 311 maximum interruptible transportation rates for service in the East Zone and West Zone. Our filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some also filed protests. The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. By order of February 28, 2008, the FERC extended the time period in this docket by 120 days and encouraged the parties to settle. No action has yet been taken by the FERC and the parties are currently in settlement negotiations. On March 27, 2009, we filed a new rate case with the FERC to establish initial rates for a new firm Section 311 service and updated rates for interruptible Section 311 service. 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, we incurred approximately $7.9 million 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 commercial and industrial customers would be impacted first, with residential 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 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. 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 $4.50 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. 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, 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. 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 $4.50 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, 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 pursuant to Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), and are executed based upon management-established price targets. We utilize hedge accounting under SFAS No. 133 to manage commodity exposure for 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. We intend to hedge approximately 70 percent of our NGLs volumes when market conditions dictate. As of December 31, 2008, we had hedged approximately 65 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 86 percent for 2009, 77 percent for 2010 and 37 percent for 2011. As of December 31, 2008, 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, for 2009. 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. 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 & 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 and 2008, revenues from our firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million and $104.4 million, respectively, of which $47.6 million, $47.4 million and $47.5 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $15.3 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, 2009, the contract will remain in effect at least through April 30, 2010. 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 |
| • | fires and explosions. |
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 recent turmoil in the financial markets, 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 12 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 recent market turmoil. 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 LLC (including its predecessor, Enogex Inc.), together with its subsidiaries (“Enogex,” the “Company,” “we,” “us” and “our”), is a provider of integrated natural gas midstream services. We are engaged in the business of gathering, processing, transporting and storing natural gas. 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.
Historically, we had also 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.
Strategy
Our results of operations are determined primarily by the volumes of natural gas transported on our intrastate pipeline system, volumes of natural gas stored at our storage facilities and the level of fees charged to our customers for such services. We generate a majority of our revenues and margins for our pipeline business under fee-based transportation contracts that are directly related to the volume of natural gas capacity reserved on our system. The margin we earn from our transportation activities is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. Results of operations from the gathering and processing business are determined primarily by the volumes of natural gas we gather and process, our current contract portfolio and natural gas and NGLs prices. 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 gathering and processing business. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering 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.
We plan to continue to implement improvements to enhance the long-term financial performance of our mid-continent assets through more efficient operations and effective commercial management of the assets, capturing growth opportunities through expansion projects and increased utilization of existing assets and strategic acquisitions. In addition, we are seeking to diversify our gathering, processing and transportation businesses principally by expanding into other geographic areas that are complementary with OGE Energy’s strategic capabilities. Over the past several years, we have initiated multiple organic growth projects. Currently, our organic growth capital expenditures are focused on three primary areas:
| • | 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; |
| • | expansions on the east side of our gathering system, primarily in the Woodford Shale play in southeastern Oklahoma through construction of new facilities and expansion of existing facilities and our 50 percent interest in the Atoka Midstream, LLC joint venture (“Atoka”); and |
| • | expansions on the west side of our gathering system, primarily in the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle. |
In addition to focusing on growing our earnings, we have reduced our exposure to changes in commodity prices and minimized our exposure to keep-whole processing
arrangements. Our profitability increased significantly from 2003 to 2008 due to the performance improvement plan initiated in 2002 as well as an overall favorable business environment coupled with higher commodity prices. While we believe substantial progress has been achieved, additional opportunities remain. We continue to review our work processes, evaluate the rationalization of assets, negotiate better terms for both new contracts and replacement contracts, manage costs and pursue opportunities for organic growth, all in an effort to further improve our cash flow and net income, while at the same time decreasing the volatility associated with commodity prices.
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 and 2008, revenues attributed to OG&E were approximately $47.6 million, $47.4 million and $47.5 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 and 2008, OERI recorded revenues from Enogex of approximately $107.1 million, $95.2 million and $41.7 million, respectively, for the sale, at market rates, of natural gas. For the years ended December 31, 2006, 2007 and 2008, we recorded revenues from OERI of approximately $291.9 million, $304.3 million and $307.2 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 three months ended March 31, 2009 and March 31, 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 three months ended March 31, 2009 and March 31, 2008 attached hereto as Exhibit B and (3) the Company’s Management’s Discussion and Analysis attached hereto as Exhibit C.
We adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” effective January 1, 2009, which required us to change the presentation of noncontrolling interests in the Company’s consolidated financial statements for our 50 percent ownership interest in the Atoka joint venture. The results of operations data for the three months ended March 31, 2008 have been adjusted to reflect the adoption of SFAS No. 160; 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 the adoption of SFAS No. 160 in order to be consistent with our previously audited consolidated financial statements.
Selected Financial Information
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Selected Financial Data |
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Results of Operations Data |
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Operating revenues | $ 190.1 | $ 266.7 | $1,103.2 | $2,065.2 | $2,367.8 | $4,340.1 | $3,372.2 | |
Cost of goods sold | 105.6 | 171.3 | 710.2 | 1,712.1 | 2,060.4 | 4,090.4 | 3,118.2 | |
Gross margin on revenues | 84.5 | 95.4 | 393.0 | 353.1 | 307.4 | 249.7 | 254.0 | |
Other operating expenses | 52.7 | 49.8 | 207.8 | 189.6 | 168.6 | 152.4 | 158.4 | |
Operating income | 31.8 | 45.6 | 185.2 | 163.5 | 138.8 | 97.3 | 95.6 | |
Interest income | 0.1 | 1.3 | 2.5 | 9.2 | 11.1 | 2.9 | 3.2 | |
Other income | — | 0.1 | 1.0 | 0.9 | 7.7 | 0.8 | 4.5 | |
Other expense | 0.1 | 0.1 | 1.4 | 1.3 | 0.3 | 0.3 | 0.3 | |
Minority interest | — | — | 6.1 | 1.0 | — | — | — | |
Interest expense | 5.9 | 8.1 | 32.7 | 31.6 | 31.8 | 32.6 | 32.2 | |
Income tax expense | 9.7 | 14.7 | 57.3 | 53.5 | 48.0 | 23.4 | 26.4 | |
Income from continuing |
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operations | 16.2 | 24.1 | 91.2 | 86.2 | 77.5 | 44.7 | 44.4 | |
Income from discontinued |
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operations, net of tax | — | — | — | — | 36.0 | 49.8 | 11.6 | |
Net income | 16.2 | 24.1 | 91.2 | 86.2 | 113.5 | 94.5 | 56.0 | |
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to noncontrolling interest | 0.8 | 1.6 | — | — | — | — | — | |
Net Income Attributable to |
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Enogex LLC | $ 15.4 | $ 22.5 | $ 91.2 | $ 86.2 | $ 113.5 | $ 94.5 | $ 56.0 | |
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Property, plant and equipment, |
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net (B) | $1,319.8 | $1,034.7 | $1,261.4 | $ 985.1 | $ 865.7 | $ 875.9 | $1,016.5 | |
Total assets | 1,518.8 | 1,228.5 | 1,458.3 | 1,356.8 | 1,319.8 | 1,652.6 | 1,719.7 | |
Long-term debt (C)(D) | 600.7 | 402.6 | 520.9 | 402.8 | 406.7 | 407.6 | 512.1 | |
Total stockholder’s equity (E) | — | 366.9 | — | 378.9 | 400.0 | 440.4 | 491.0 | |
Total member’s interest (E) | 439.5 | — | 379.7 | — | — | — | — | |
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Capitalization Ratios (at period end) (F) |
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Stockholder’s equity | N/A | 47.7% | N/A | 48.5% | 49.6% | 51.9% | 48.9% | |
Member’s interest | 42.3% | N/A | 42.2% | N/A | N/A | N/A | N/A | |
Long-term debt | 57.7% | 52.3% | 57.8% | 51.5% | 50.4% | 48.1% | 51.1% | |
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Ratio of earnings to fixed charges | 4.08 | 5.42 | 4.96 | 5.24 | 4.77 | 3.06 | 3.17 | |
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(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 three months ended March 31, 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 1.57 trillion British thermal units per day (“TBtu/d”) of average daily throughput during 2008. 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.
We deliver natural gas to most interstate and intrastate pipelines and end-users connected to our systems from 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). At December 31, 2008, we were connected to 11 third-party natural gas pipelines and had 63 interconnect points. These interconnections include Panhandle Eastern Pipe Line, Southern Star Central Gas Pipeline (formerly Williams Central), Natural Gas Pipeline Company of America, Oneok Gas Transmission, Northern Natural Gas Company, ANR Pipeline, Western Farmers Electric Cooperative, CenterPoint Energy Gas Transmission Co., El Paso Natural Gas Pipeline, Quest Pipelines (“KPC”) and Ozark Gas Transmission, L.L.C. Further, we are connected to 24 end-user customers, including 15 natural gas-fired electric generation facilities in Oklahoma.
We own and operate two natural gas storage facilities in Oklahoma, the Wetumka Storage Facility and the Stuart Storage Facility. These storage facilities are currently being operated at a working gas level of approximately 24 Bcf and have approximately 650 million cubic feet per day (“MMcf/d”) of maximum withdrawal capability and approximately 650 MMcf/d of injection capability. We offer both fee-based firm and interruptible storage services to third parties. Services offered under Section 311 of the NGPA are pursuant to terms and conditions specified in our Statement of Operating Conditions (“SOC”) for gas storage and at market-based rates negotiated with each customer. Our storage facilities are also used to support our no-notice load following transportation and storage contract with OG&E, the largest electric utility in Oklahoma and a wholly-owned subsidiary of OGE Energy.
We use our storage assets to meet our contractual obligations under certain load following transportation contracts. We also periodically conduct an open season to solicit commitments for contracted capacity and deliverability to third parties for contracts that generally do not exceed three years.
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, 2009, the contract will remain in effect at least through April 30, 2010. 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 and 2008, revenues from our firm intrastate transportation and storage contracts were approximately $98.1 million, $103.9 million and $104.4 million, respectively, of which approximately $47.6 million, $47.4 million and $47.5 million, respectively, was attributed to OG&E and $13.3 million, $13.3 million and $15.3 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 and 27 percent in 2008.
Competition
Our transportation and storage assets compete with numerous interstate and intrastate pipelines, including several of the interconnected pipelines discussed above, and storage facilities in providing transportation and storage services for natural gas. The principal elements of competition are rates, terms of services, flexibility and reliability of service. Natural gas-fired electric generation facilities contribute their highest value when they have the capability to provide load following service to the customer (i.e., the ability of the generation facility to regulate generation to respond to and meet the instantaneous changes in customer demand for electricity). While the physical characteristics of natural gas-fired electric generation facilities are known to provide quick start-up, on-line functionality and the ability to efficiently provide varying levels of electric generation relative to other forms of generation, a key part of their effectiveness is contingent upon having access to an integrated pipeline and storage system that can respond quickly to meet their corresponding fluctuating fuel needs. We believe that we are well positioned to compete for the needs of these generators due to the ability of our transportation and storage assets to provide no-notice load following service.
Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas or other forms of energy as well as weather and other factors affect the demand for natural gas on our system.
Regulation
The transportation rates we charge for transporting natural gas in interstate commerce are subject to the jurisdiction of the FERC 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. The rate review may, but will not necessarily, involve an administrative-type hearing before the FERC Staff panel and an administrative appellate review. In the past, we have successfully settled, rather than litigated, our Section 311 rate cases. Offering interruptible Section 311 transportation gives us the opportunity to utilize any unused capacity on an interruptible basis in interstate commerce and thus increase our transportation revenues without increasing our regulatory burden appreciably. We currently have two zones under our Section 311 rate structure—an East Zone and a West Zone with a maximum transportation rate and a fuel retention rate for each zone. We may charge up to our maximum established zonal East and West transportation rates for transportation in one zone or cumulative
maximum rates for transportation in both zones and the applicable fixed zonal fuel percentage(s) for the fuel used in shipping natural gas under Section 311 on the Enogex system.
The fixed zonal fuel percentages are adjusted annually and remain in effect for a calendar year. The mechanism used to establish the percentages is a fuel tracker filed annually at the FERC to establish prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year. Fuel usage is later trued-up to actual usage over a two-year period based on the value of the gas at the time of usage.
On October 1, 2007, we made our required triennial rate filing at the FERC to update our Section 311 maximum interruptible transportation rates for service in the East Zone and West Zone. Our filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some also filed protests.
The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. By order of February 28, 2008, the FERC extended the time period in this docket by 120 days and encouraged the parties to settle. No action has yet been taken by the FERC and the parties are currently in settlement negotiations.
On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex rate case with a separate Enogex application pending before the FERC allowing us to lease firm capacity to Midcontinent Express Pipeline, LLC (“MEP”) and with separate applications filed by MEP with the FERC for a certificate to construct and operate the new MEP pipeline and to lease firm capacity from us. Additional pleadings were also filed by this intervenor after the initial protest and we and MEP separately opposed this intervenor’s assertions. By order dated July 25, 2008, the FERC approved the MEP project and denied the intervenors’ request for consolidation of the MEP proceedings with the Enogex rate case. The intervenor filed a request for rehearing in the MEP project and lease proceedings. The FERC denied the request for rehearing, and we commenced service to MEP under the lease agreement on June 1, 2009.
We did not place the increased rates filed in the 2007 rate proceeding into effect. We would have had a regulatory obligation to file our next rate case no later than October 1, 2010 to comply with the FERC’s requirement for triennial filings, but, instead, we filed a new rate case on March 27, 2009 in order to establish initial rates for a new firm Section 311 service and updated rates for interruptible Section 311 service.
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, Enogex had filed a revised SOC Applicable to Transportation Services 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. The regulations provide that the FERC has 150 days to act on the rate filing but also permit the issuance of an order extending the time period for action.
On November 21, 2008, we made our annual filing to establish fixed fuel percentages for our East Zone and West Zone, respectively, for calendar year 2009 (“2009 Fuel Year”). The FERC accepted the proposed zonal fuel percentages for the 2009 Fuel Year by an order dated January 8, 2009.
The FERC regulates our Section 311 transportation services but does not regulate our gathering services. In addition, the FERC does not regulate our intrastate transportation services because these services are not Section 311 services. These services include those intrastate transportation services provided to the gas-fired electric generation facilities and other end users within Oklahoma. Therefore, the rates we charge for transporting natural gas for the Oklahoma utility companies, independent electric generation facilities and other shippers within Oklahoma are not subject to FERC regulation. Nor are the rates we charge for any intrastate transportation service subject to direct state regulation by the Oklahoma Corporation Commission (“OCC”). However, the OCC, the Arkansas Public Service Commission and the FERC (all of which approve various electric rates of OG&E) have the authority to examine the appropriateness of any transportation charges or other fees paid by OG&E to us which OG&E seeks to recover from its ratepayers in its cost-of-service for electric service.
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, we incurred approximately $7.9 million 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 MEP for a primary term of ten years (subject to possible extension) that would give MEP and its shippers access to capacity on our system. The quantity of capacity subject to the MEP lease agreement is currently 272 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 includes construction by MEP of a new pipeline originating near Bennington, Oklahoma and terminating in Butler, Alabama. We currently estimate that our capital expenditures related to this project will be 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 are proceeding 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.
Gathering and Processing
General
We provide well connect, gathering, measurement, treating, dehydration, compression and processing services for various types of producing wells owned by various sized producers who are active in the areas in which we operate. Most natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This high-content, or “rich,” natural gas is generally not acceptable for transportation in the nation’s transmission pipeline system or for commercial use. The streams of processable natural gas gathered from wells and other sources are gathered into our gas gathering systems and are delivered to processing plants for the extraction of NGLs, leaving residual dry gas that meets transmission pipeline and commercial quality specifications. Furthermore, the processing plants produce NGLs.
Our gathering system includes approximately 5,763 miles of natural gas gathering pipelines with approximately 1.16 TBtu/d of average daily throughput during 2008 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 own and operate six natural gas processing plants with a total inlet capacity of approximately 723 MMcf/d, have a 50 percent interest in and operate an additional natural gas processing plant with an inlet capacity of approximately 20 MMcf/d and have access to capacity up to 50 MMcf/d in two third-party plants, all in Oklahoma. Where the quality of natural gas received dictates the removal of NGLs, such gas is aggregated through the gathering system to
the inlet of one or more of the seven processing plants we operate or the two leased plants. The resulting processed stream of natural gas is then delivered from the tailgate of each plant into our intrastate natural gas transportation system. For the year ended December 31, 2008, we extracted and sold approximately 426 million gallons of NGLs.
In 2007, 2008 and 2009, we have pursued and expect to pursue several projects to address tightening processing capacity as a result of increasing supply:
| • | In July 2007, we completed a restaging of two compression turbines at the Thomas processing plant, which allowed for the realization of fuel savings at that plant. |
| • | We will consider building or acquiring additional processing capacity in areas where the capacity is needed. We completed construction of a new 100 MMcf/d refrigeration dew point conditioning plant in Roger Mills County of Oklahoma, which became operational in August 2008. In addition, we are constructing a new 120 MMcf/d cryogenic plant equipped with electric compression near Clinton, Oklahoma. This plant will process new gas developing in the area and is expected to be in service by September 2009. Also, we have placed an order for a cryogenic processing plant that is scheduled for delivery in the fourth quarter of 2009, which is expected to add another 120 MMcf/d of processing capacity to our system. |
Our gathering and processing business has approximately 276,000 horsepower of owned compression. We also have our own compression overhaul center and specialized compression workforce.
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. |
• | 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 |
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| 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. |
| • | 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. |
In addition, as a seller of NGLs, we are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, in 2002, we revised our SOC used as part of our typical natural gas processing arrangements and included language that requires a “default processing fee” in the event the gathered gas exceeds downstream interconnect specifications. Natural gas that is greater than 1,080 Btu per cubic foot coming out of wells must typically be processed before it can enter an interstate pipeline. The default processing fee stipulates a fee to be paid to the processor if the market for NGLs is lower than the gas equivalent Btu value of the natural gas that is removed from the stream. The default processing fee helps to minimize the risk of processing gas that is greater than 1,080 Btu per cubic foot when the price of the NGLs to be extracted and sold is less than the Btu value of the natural gas that we otherwise would be required to replace.
We are active in the extraction and marketing of NGLs from natural gas. The liquids extracted include condensate liquids, marketable ethane, propane, butanes and natural gasoline
mix. The residue gas remaining after the liquid products have been extracted consists primarily of ethane and methane.
Approximately 17 percent of the commercial grade propane produced at our plants is sold on the local market. The balance of propane and the other NGLs we produce is delivered into pipeline facilities of a third party and transported to Conway, Kansas and Mont Belvieu, Texas, where they are sold under contract or on the spot market. Ethane, which may be optionally produced at all of our plants except the Calumet plant, is also sold under contract or on the spot market.
Our large diameter, rich gas gathering pipelines in western Oklahoma are configured such that natural gas from the Wheeler County area in the Texas Panhandle can flow to the Cox City, Thomas or Calumet gas processing plants. These large-diameter “super-header” gathering systems provide gas routing flexibility for us to optimize the economics of our gas processing and to improve system utilization and reliability.
Several of our processing plants are currently operating at or near full capacity, such as the Cox City processing plant. As we experience increased growth in regions such as the Woodford Shale play, we will evaluate the need to expand our processing plants in order to meet the growing needs of our producer customers.
Natural Gas Supply
As of December 31, 2008, approximately 3,278 wells and approximately 266 central receipt points were connected to our system in Oklahoma and the Texas Panhandle area, areas that have experienced an increase in drilling activity and production. We have secured significant areas of dedication from numerous customers active throughout our areas of operations.
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 include 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.
Competition
Competition for natural gas supply is primarily based on efficiency and reliability of operations, customer service, proximity to existing assets, access to markets and pricing. Competition to gather and process non-dedicated gas is based on providing the producer with the highest total value, which is primarily a function of gathering rate, processing value, system
reliability, fuel rate, system run time, construction cycle time and prices at the wellhead. We believe we will be able to continue to compete effectively. We compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. Our primary competitors are master limited partnerships who are active in our region, including Atlas Pipeline Partners, L.P., Crosstex Energy LP, DCP Midstream Partners, LP, Enbridge Energy Partners, L.P., Hiland Partners, LP, MarkWest Energy Partners, L.P. and Oneok Partners, L.P. In processing and marketing NGLs, we compete against virtually all other gas processors extracting and selling NGLs in our market area.
Regulation
State regulation of natural gas gathering facilities generally includes various safety, environmental and nondiscriminatory rate and open access requirements and complaint-based rate regulation. We may be subject to state common carrier, ratable take and common purchaser statutes. The common carrier and ratable take statutes generally require gatherers to carry, transport and deliver, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers that purchase gas to purchase without undue discrimination as to source of supply or producer. These statutes may have the effect of restricting our right to decide with whom we contract to purchase natural gas or, as an owner of gathering facilities, to decide with whom we contract to purchase or gather natural gas.
Oklahoma and Texas have each adopted a form of complaint-based regulation of gathering operations that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering open access and rate discrimination. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (the “Competition Bill”) and H.B. 1920 (the “Lost and Unaccounted for Gas (“LUG”) Bill”). The Texas Competition Bill and LUG Bill contain provisions applicable to various natural gas industry participants, including gatherers. The Competition Bill allows the Railroad Commission of Texas (“TRRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings, if a complaint is filed and a determination is made that such a rate is necessary to remedy unreasonable discrimination. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to impose administrative penalties against purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It expands the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders for purposes of preventing waste in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. To date, neither the Competition Bill nor the LUG Bill has had a significant impact on our operations. However, we cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our gathering operations in the future.
Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be subject to additional 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 or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Recent System Expansions
Over the past several years, we have initiated multiple organic growth projects. Currently, in our gathering and processing business, organic growth capital expenditures are focused on expansions on the east side of our gathering system, primarily in the Woodford Shale play in southeastern Oklahoma through the construction of new facilities and expansion of existing facilities and the interest in the joint venture, Atoka, and expansions on the west side of our gathering system, primarily in the Granite Wash play and Atoka play in the Wheeler County, Texas area, which is located in the Texas Panhandle.
We are expanding in the Woodford Shale play and have several projects either completed or scheduled for completion in 2008, 2009 and 2010. For example, in December 2006, we entered into a joint venture arrangement with Pablo Gathering, LLC, a subsidiary of Pablo Energy II, LLC, a Texas-based exploration and production company, which resulted in the formation of the Atoka joint venture. Atoka constructed, owns and/or operates a gathering system and processing plant and related facilities relating to production in certain areas in southeastern Oklahoma. The gathering system and processing plant were placed in service during the third quarter of 2007. We own a 50 percent membership interest in Atoka and act as the managing member and operator of the facilities owned by the joint venture. The joint venture plans to expand its gathering pipeline infrastructure in order to accommodate additional production in the area. In 2009, our capital expenditures associated with the pipeline expansion of Atoka are expected to be approximately $5 million. In addition, in order to accommodate the increased drilling activity in Canadian County, Oklahoma, we plan to add approximately six miles of 12-inch steel pipe and another 10 MMcf/d of compression capacity to our Grandview gathering project in 2009. The capital expenditures associated with the additional pipe and compression capacity are expected to be approximately $9 million.
In February 2008, we completed construction of a new 20-mile pipeline project that connects our Hughes, Coal and Pittsburgh County gathering system with the 30-inch Enogex mainline pipeline to Bennington, Oklahoma, and the 24-inch Enogex mainline pipeline to Wilburton, Oklahoma. The gathering project created additional gathering capacity of 75 MMcf/d for customers desiring low-pressure services. The pipeline is complemented by approximately 16,000 horsepower of new gathering compression which was completed in the third quarter of 2008. In June 2009, we added approximately 16 miles of 20-inch steel pipe to our system with an expected throughput capacity of approximately 300 MMcf/d. Also, we are planning to lease 60 MMcf/d of additional treating facilities, which are expected to be in service by late 2009 or early 2010. The capital expenditures associated with the additional treating facilities are expected to be approximately $2.6 million.
In August 2006, we completed a project to expand our gathering pipeline capacity in the Granite Wash play and Atoka play in the Wheeler County, Texas area of the Texas Panhandle that has allowed us to benefit from growth opportunities in that marketplace. Since the pipeline was put in service, we have completed the construction of five new gas gathering compressor stations totaling approximately 26,500 horsepower of compression, and several miles of
gathering pipe, including a new 16-inch line that extends the original pipeline project an additional 20 miles to the west. We are continuing to expand in the Wheeler and Hemphill counties in Texas and expect to add another 8,000 horsepower of low pressure compression to the Wheeler area by July 2009.
We are in the process of expanding our gathering facilities in the Southeastern Oklahoma area and plan to add approximately four miles of 16-inch gathering pipe, approximately 2,600 horsepower of additional compression and 25 MMcf/d of additional treating facilities, all of which are expected to be in service by the fourth quarter of 2009. The capital expenditures associated with the additional pipe and treating facilities are expected to be approximately $11.6 million.
Technology Improvements
We continue to upgrade our data and information systems in order to improve operational efficiencies and increase profitability of our business and that of our customers.
| • | In July 2008, we completed implementation of an information system to support our NGLs business. The system is expected to strengthen compliance capabilities, evaluate our risk position, manage our credit exposure, improve invoicing accuracy and provide for easier data extraction in support of work activities and decision making. |
| • | We continue to improve our state-of-the-art Supervisory Control and Data Acquisition system, which provides a single system for pipeline equipment control, data collection, management and measurement of gas volumes and pressures. |
| • | An information system which has been implemented, together with our primary enterprise-wide general ledger software, and has been used to accumulate and analyze financial data used in financial reporting. This change in information systems was made to eliminate previous stand-alone systems and integrate them into one system. |
| • | We continue to enhance our digital asset mapping system that was implemented in May 2006. This system has improved access to pipeline equipment and system information. This information can be used for existing asset management activities including daily operations and maintenance, budgeting, planning and new project development. |
Safety and Health Regulation
We are subject to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within ten years. The DOT has developed regulations implementing the PSAI that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
A four-mile portion of our pipeline is also subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996 (the “Hazardous Liquid Pipeline Safety Act”) and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of liquid pipeline facilities. The Hazardous Liquid Pipeline Safety Act covers petroleum and petroleum products and requires any entity that owns
or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the U.S. Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in material compliance with these Hazardous Liquid Pipeline Safety Act regulations.
States may be preempted by federal law from solely regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In the State of Oklahoma, the OCC’s Transportation Division, acting through the Pipeline Safety Department, administers the OCC’s intrastate regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipeline. The OCC develops regulations and other approaches to assure safety in design, construction, testing, operation, maintenance and emergency response to pipeline facilities. The OCC derives its authority over intrastate pipeline operations through state statutes and certification agreements with the DOT. A similar regime for safety regulation is in place in Texas and administered by the Texas Railroad Commission. We anticipate that we should be able to comply with currently existing state laws and regulations applicable to pipeline safety without incurring material costs. Our natural gas pipelines have inspection and compliance programs designed to maintain compliance with pipeline safety and pollution control requirements.
In addition, we are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state statutes, whose purpose is to protect the safety and health of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. We have an internal program of inspection designed to monitor and enforce compliance with worker safety and health requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker safety and health.
Environmental Matters
General
Our activities are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can handle or dispose of our wastes, requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with
permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment. We handle some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”) and comparable state statutes, prepare and file reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtain permits pursuant to the Federal Clean Air Act and comparable state air statutes.
We believe that our operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing Federal, state and local environmental laws and regulations will not have a material adverse effect on our business, consolidated financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. For example, earlier this year, the EPA initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing the 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. As a result, there can be no assurance as to amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts currently anticipated. Moreover, we cannot assure that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Approximately $0.6 million of our capital expenditures budgeted for 2009 are to comply with environmental laws and regulations. Approximately $0.6 million of our capital expenditures budgeted for 2010 are to comply with environmental laws and regulations. It is estimated that our total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $4.3 million during 2009 as compared to approximately $3.6 million during 2008. Management continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position it in a competitive market. See Note 13 of Notes to the Consolidated Financial Statements for the year ended December 31, 2008 for a discussion of environmental matters, including the impact of existing and proposed environmental legislation and regulations.
Hazardous Waste
Our operations generate hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 (“RCRA”) as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of hazardous
waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other waste associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial waste such as paint waste, waste solvents and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”) (also known as “Superfund”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Because we utilize various products and generate wastes that either are or otherwise contain CERCLA hazardous substances, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where those substances have been released to the environment. At this time, it is not anticipated that any associated liability will cause any significant impact to us.
We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, compression and processing of natural gas. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbon or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators) or remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills).
Air Emissions
Our operations are subject to the Federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and operational limitations, install emission control equipment or subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We likely will be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions. See Note 13 of Notes to the Consolidated Financial Statements for the year ended December 31, 2008 and Note 12 of Notes to the Condensed Consolidated Financial Statements for the quarter ended March 31, 2009 for a discussion of potentially significant environmental capital expenditures related to air emissions.
Water Discharges
Our operations are subject to the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedial obligations. See Note 13 of Notes to the Consolidated Financial Statements for the year ended December 31, 2008 for a discussion of water intake matters.
Other Laws and Regulations
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. For instance, at least nine states in the Northeast (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York and Vermont) and five states in the West (Arizona, California, New Mexico, Oregon and Washington) have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. On April 17, 2009, the EPA issued a proposed endangerment 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 finding now enters the public comment period, which is the next step in the deliberative process the EPA must undertake before issuing final findings. Before taking any steps to propose regulations to reduce greenhouse gases under the Federal Clean Air Act, the EPA would conduct a regulatory process and consider stakeholder input. Notwithstanding this regulatory process, 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 regulations regarding the reduction of greenhouse gases could result in significant capital expenditures by us and a significant increase in our cost of conducting business. In addition, the EPA has initiated a proposed rule requiring measuring and reporting of greenhouse gas emissions. If this rule is finalized as proposed, we may incur significant costs to comply with the monitoring, collection and reporting requirements on our affected facilities. The current proposed effective date for gathering the data is January 2010 with the first mandatory reporting date as 2011.
Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The enactment of climate control laws or regulations that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our services or products. We are a partner in the EPA Natural Gas STAR Program, a voluntary program to reduce methane emissions.
Litigation
United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and OG&E (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.), United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, OGE Energy was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (1) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (2) certain provisions generally found in gas purchase contracts are improper; (3) transactions by affiliated companies are not arms-length; (4) excess processing cost deduction; and (5) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (1) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (2) treble damages; (3) civil penalties; (4) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (5) interest, costs and attorneys’ fees.
In qui tam actions, the Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.
The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming.
In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that OG&E and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.
On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s district court appeal, following and confirming the recommendation of the special master dismissing all claims against us, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006. The defendants filed motions for attorneys’ fees and other legal costs on various bases. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. On November 15, 2006, Grynberg filed appeals with the Tenth Circuit Court of Appeals. Briefing on the Tenth Circuit appeals was completed by Grynberg and defendants and oral arguments were made to the Tenth Circuit Court on September 25, 2008. On March 17, 2009, the Tenth Circuit Court of Appeals affirmed the October 2006 order of the District Court of Wyoming dismissing the complaints against all gas defendants, including us. On April 14, 2009, Grynberg filed a petition for rehearing in the Tenth Circuit Court of Appeals. By order dated May 4, 2009, the Tenth Circuit Court denied Grynberg’s request for rehearing. We continue to vigorously defend this action and are optimistic that with the affirmation of the ruling in the defendants’ favor by the Tenth Circuit Court this case will end, or will ultimately be upheld in any further appeals; however we are unable to predict with certainty the timing and outcome of a further appeal nor estimate the amount or range of potential loss to us if the outcome of the appeal is unfavorable.
Will Price, et al. v. El Paso Natural Gas Co., et al. (“Price I”). On September 24, 1999, various subsidiaries of OGE Energy, including us, were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of OGE Energy’s other subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.
On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of OGE Energy filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.
We intend to vigorously defend this action. At this time, we are unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to us.
Will Price, et al. v. El Paso Natural Gas Co., et al. (“Price II”). On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case. OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of OGE Energy were named in this case. The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.
Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.
On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of OGE Energy filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification.
We intend to vigorously defend this action. At this time, we are unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to us.
Oklahoma Royalty Lawsuit. On July 22, 2005, we, along with certain other unaffiliated co-defendants, were served with a purported class action which had been filed on February 7, 2005 by Farris Buser and other named plaintiffs in the District Court of Canadian County, Oklahoma. The plaintiffs own royalty interests in certain oil and gas producing properties and allege they have been under-compensated by the named defendants, including us and our subsidiaries, relating to the sale of liquid hydrocarbons recovered during the transportation of natural gas from the plaintiffs’ wells. The plaintiffs assert breach of contract, implied covenants, obligation, fiduciary duty, unjust enrichment, conspiracy and fraud causes of action and claim actual damages in excess of $10,000, plus attorneys’ fees and costs, and punitive damages in excess of $10,000. We filed a motion to dismiss which was granted on November 18, 2005, subject to the plaintiffs’ right to conduct discovery and the possible re-filing of their allegations in the petition against us. On September 19, 2005, the co-defendants, BP America, Inc. and BP
America Production Co. (collectively, “BP”), filed a cross claim against Enogex Products Corporation, a wholly-owned subsidiary of ours (“Products”), seeking indemnification and/or contribution from Products based upon the 1997 sale of a third-party interest in one of Products natural gas processing plants. On May 17, 2006, the plaintiffs filed an amended petition against us. We filed a motion to dismiss the amended petition on August 2, 2006. The hearing on the dismissal motion was held on November 20, 2006 and the court denied our motion. We filed an answer to the amended petition and BP’s cross claim on January 16, 2007. Based on our investigation to date, we believe these claims and cross claims in this lawsuit are without merit and intend to continue vigorously defending this case.
Hull v. Enogex LLC. On November 14, 2008, a natural gas gathering pipeline owned by us ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused injuries to one resident and destroyed three residential structures. The cause of the rupture is not known and an investigation of the incident is ongoing. On May 13, 2009, the injured resident and her husband filed a legal action in the State District Court of Cleveland County, Oklahoma against Enogex LLC, Enogex Gas Gathering LLC, OGE Enogex Holdings LLC and OGE Energy(Case No. CJ-2009-1053) seeking to recover unspecified actual and punitive damages. No discovery has been conducted and we continue to evaluate the claims alleged in this action. It is anticipated that the resolution of this action will not be material to us.
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 the Company’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:
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(In millions) | Total | 2009 | 2011 | 2013 | 2014 |
Base Maintenance and Known and |
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Committed Projects | $ 446.2 | $ 229.1 | $ 82.1 | $ 90.0 | $ 45.0 |
Maturities of long-term debt | 520.0 | — | 400.0 | 120.0 | — |
Interest payments on long-term debt | 73.3 | 40.5 | 26.6 | 6.2 | — |
Pension funding obligations | 20.0 | — | 10.0 | 10.0 | — |
Total capital requirements | 1,059.5 | 269.6 | 518.7 | 226.2 | 45.0 |
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Operating lease obligations |
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Enogex noncancellable operating leases | 8.7 | 4.2 | 4.1 | 0.4 | — |
Total operating lease obligations | 8.7 | 4.2 | 4.1 | 0.4 | — |
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Other purchase obligations and commitments |
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Other | 36.2 | 5.4 | 10.8 | 11.9 | 8.1 |
Total other purchase obligations and |
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commitments | 36.2 | 5.4 | 10.8 | 11.9 | 8.1 |
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Total capital requirements, operating lease |
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obligations and other purchase obligations |
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and commitments | $ 1,104.4 | $ 279.2 | $ 533.6 | $ 238.5 | $ 53.1 |
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.
Issuance of Long-Term Debt
On April 1, 2008, Enogex entered into a $250 million unsecured five-year revolving credit facility. Subject to certain limitations, the facility provides Enogex with the option, exercisable annually, to extend the maturity of the facility for an additional year and, upon the expiration of the revolving term, an option to convert the outstanding balance under the facility to a one-year term loan. The facility provides the option for Enogex to increase the borrowing limit by up to an additional $250 million (to a maximum of $500 million) upon the agreement of the lenders (or any additional lender) and the satisfaction of other specified conditions. The facility contains customary representations, warranties, covenants and defaults applicable to Enogex and its subsidiaries. The facility contains a financial covenant requiring Enogex to
maintain a ratio of consolidated funded debt to consolidated EBITDA (in each case, as defined in the Credit Agreement) as of the last day of each fiscal quarter of less than or equal to 5.00 to 1.00; provided that, for any three fiscal quarters including and following any fiscal quarter in which the aggregate value of one or more acquisitions made by Enogex or its subsidiaries exceeds $25 million in the aggregate for the prior twelve-month period, the consolidated funded debt to EBITDA ratio as of the last day of each fiscal quarter would be permitted to be up to 5.50 to 1.00. The facility also generally limits dividend payments by Enogex’s subsidiaries to ratable distributions and prohibits certain affiliated transactions. At December 31, 2008, there was $120.0 million outstanding under the facility. These borrowings are not expected to be repaid within the next 12 months, therefore, they are classified as long-term debt for financial reporting purposes.
Long-Term Debt Maturities
Maturities of Enogex’s long-term debt during the next five years consist of $400.0 million in 2010 and the outstanding balance under Enogex’s revolving credit facility in 2013. At March 31, 2009, there was approximately $200.0 million outstanding under Enogex’s revolving credit facility.
At March 31, 2009, Enogex had approximately $67.0 million of cash on hand. At March 31, 2009, Enogex had approximately $50.0 million of net available liquidity under its revolving credit agreement.
Cash Flows
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| Ended March 31, | Year Ended December 31, | |||
(In millions) | 2009 | 2008 | 2008 | 2007 | 2006 |
Net cash provided from (used in) operating |
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activities | $ (8.6) | $ 18.5 | $242.0 | $ 107.8 | $ 131.6 |
Net cash used in investing activities | (73.2) | (62.2) | (331.3) | (165.5) | (65.1) |
Net cash provided from (used in) financing |
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activities | 131.7 | 42.5 | 103.2 | 60.9 | (139.4) |
The decrease of approximately $27.1 million in net cash provided from operating activities during the three months ended March 31, 2009 as compared to the same period in 2008 was primarily due to a decrease in sales and purchases due to a decrease in NGLs and natural gas prices and volumes in the first quarter of 2009 as compared to the same period in 2008.
The increase of approximately $11.0 million in net cash used in investing activities during the three months ended March 31, 2009 as compared to the same period in 2008 related to higher levels of capital expenditures primarily related to various transportation and gathering projects.
The increase of approximately $89.2 million in net cash provided from financing activities during the three months ended March 31, 2009 as compared to the same period in 2008 primarily related to proceeds received from borrowings under Enogex’s revolving credit agreement during the three months ended March 31, 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 Enogex’s transportation, storage, gathering and processing assets. Enogex’s current estimates of capital expenditures are approximately: 2009 - $229.1 million, 2010 - $43.5 million, 2011 - $38.6 million, 2012 - $45.0 million, 2013 - $45.0 million and 2014 - $45.0 million. For 2009, these capital expenditures include expenditures of approximately $50.6million related to expansion in the Woodford Shale play, approximately $64.0million related to expansion projects in western Oklahoma, approximately $28.3million related to expansion projects in the Texas Panhandle and approximately $36.9million related to transportation projects. These capital expenditure projections reflect base market conditions at May 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
In 2009, Enogex intends to refinance its $400.0 million medium-term notes which mature in January 2010. This offering of notes will be part of that refinancing. The refinancing of the balance of such notes is expected to occur later in 2009. Due to uncertainty in the current credit markets, at this time, Enogex cannot predict how interest rates will affect its ability to obtain financing on favorable terms.
Pension and Postretirement Benefit Plans
All eligible employees of Enogex and participating affiliates are covered by a non-contributory defined benefit pension plan sponsored by OGE Energy. During 2008, actual asset returns for OGE Energy’s defined benefit pension plan were negatively affected by the slowdown in growth in the equity markets. At December 31, 2008, approximately 45 percent of the pension plan assets were invested in listed common stocks with the balance invested in
corporate debt and U.S. Government securities. In 2008, asset returns on the pension plan decreased approximately 25.1 percent as compared to an increase of approximately 4.4 percent in 2007. During the same time, corporate bond yields, which are used in determining the discount rate for future pension obligations, have continued to decline.
During both 2008 and 2007, OGE Energy made contributions to its pension plan of approximately $50.0 million, of which none and $4.4 million, respectively, was Enogex’s portion. The level of funding is dependent on returns on plan assets and future discount rates. Higher returns on plan assets and increases in discount rates will reduce funding requirements to the plan. During 2009, OGE Energy may contribute up to $50.0 million to its pension plan, none of which is expected to be Enogex’s portion.
In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation or the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007, OGE Energy and Enogex experienced an increase in both the number of employees electing to retire and the amount of lump-sum payments to be paid to such employees upon retirement as well as the death of OGE Energy’s Chairman and Chief Executive Officer in September 2007. As a result, OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. OGE Energy did not record a pension settlement charge during 2008. The pension settlement charge and retirement restoration plan settlement charge did not require a cash outlay by Enogex and did not increase Enogex’s total pension expense or retirement restoration expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.
(In millions) | OGE Energy | Enogex’s Portion |
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Pension Settlement Charge: |
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2007 | $ 16.7 | $ 0.5 |
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Retirement Restoration Plan Settlement Charge: |
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2007 | $ 2.3 | $ — |
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As discussed in Note 11 of Notes to the Consolidated Financial Statements for the year ended December 31, 2008, in 2000 OGE Energy made several changes to its pension plan, including the adoption of a cash balance benefit feature for employees hired on or after February 1, 2000. The cash balance plan may provide lower post-employment pension benefits to employees, which could result in less pension expense being recorded. Over the near term, OGE Energy’s cash requirements for the plan are not expected to be materially different than the requirements existing prior to the plan changes. However, as the population of employees included in the cash balance plan feature increases, OGE Energy’s cash requirements should decrease and will be much less sensitive to changes in discount rates.
At December 31, 2008, the projected benefit obligation and fair value of assets of Enogex’s portion of OGE Energy’s pension plan and restoration of retirement income plan was
approximately $45.0 million and $30.2 million, respectively, for an underfunded status of approximately $14.8 million. Also, at December 31, 2008, the accumulated postretirement benefit obligation of Enogex’s portion of OGE Energy’s postretirement benefit plans was approximately $17.4 million for an underfunded status of approximately $17.4 million. The above amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss in Enogex’s Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss represent a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.
At December 31, 2007, the projected benefit obligation and fair value of assets of Enogex’s portion of OGE Energy’s pension plan and restoration of retirement income plan was approximately $40.4 million and $46.0 million, respectively, for an overfunded status of approximately $5.6 million. Also, at December 31, 2007, the accumulated postretirement benefit obligation of Enogex’s portion of OGE Energy’s postretirement benefit plans was approximately $15.2 million for an underfunded status of approximately $15.2 million. The above amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss in Enogex’s Consolidated Balance Sheet. The amounts in Accumulated Other Comprehensive Loss represent a net periodic pension cost to be recognized in the Consolidated Statements of Income in future periods.
Pension Plan Costs and Assumptions
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 OGE Energy 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 OGE Energy’s plans in order to comply with the Pension Protection Act.
Security Ratings
| Moody’s | Standard & Poor’s | Fitch’s |
Enogex Notes | Baa3 | BBB+ | BBB |
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, commodity prices, levels of drilling activity, acquisitions of other businesses and/or development of projects, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competitors.
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 commercial paper) 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 March 31, 2009 and December 31, 2008, respectively, Enogex had approximately $200.0 million and $120.0 million outstanding under its revolving credit agreement. The following table shows Enogex’s revolving credit agreement and available cash at March 31, 2009.
Revolving Credit Agreement and Available Cash (In millions) | ||||
| Aggregate | Amount | Weighted-Average |
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| Commitment | Outstanding | Interest Rate | Maturity |
Revolving Credit Agreement | $ 250.0 | $ 200.0 | 0.86% | March 31, 2013 |
Cash | 67.0 | N/A | N/A | N/A |
Total | $ 317.0 | $ 200.0 | 0.86% |
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