Item 1. BUSINESS
GENERAL
Prior to October 1, 2007, Northwest was a corporation, known as Northwest Pipeline Corporation, and was wholly-owned by Williams Gas Pipeline Company, LLC (WGP). Effective October 1, 2007, Northwest converted to a general partnership. Throughout this report, “Northwest” refers to Northwest Pipeline Corporation prior to October 1, 2007, and Northwest Pipeline GP and its consolidated affiliate, Northwest Pipeline Services LLC, thereafter. Northwest is at times referred to in the first person as “we,” “us,” or “our.”
On January 24, 2008, Williams Pipeline Partners L.P. (WMZ) (previously a wholly-owned subsidiary of The Williams Companies, Inc. (Williams)) completed its initial public offering of limited partnership units, the net proceeds of which were used to acquire a 15.9 percent interest in Northwest Pipeline GP. Williams contributed 19.1 percent of its ownership in Northwest to WMZ in return for limited and general partnership interests in WMZ. Northwest received net proceeds of $300.9 million on January 24, 2008 from WMZ for the purchase of its 15.9 percent interest, and Northwest in turn made a distribution to Williams of $300.9 million. After these transactions and through December 31, 2008, Northwest is owned 35 percent by WMZ and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of Williams. Through its ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of Northwest as of February 26, 2009.
We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through the states of Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. We provide natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Our principal business is the interstate transportation of natural gas, which is regulated by the Federal Energy Regulatory Commission (FERC).
PIPELINE SYSTEM, CUSTOMERS AND COMPETITION
Transportation and Storage
Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2008, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 Bcf* of natural gas per day.
We have access to multiple strategic natural gas supply basins, including basins in the Rocky Mountain region, the San Juan Basin and the Western Canadian Sedimentary Basin. We are the only interstate natural gas pipeline that currently provides service to certain key markets, including Seattle, Washington; Portland, Oregon; and Boise, Idaho. In addition, we believe that we provide competitively priced services in markets such as Reno, Nevada; Spokane, Washington and Medford, Oregon that are also served by other interstate natural gas pipelines.
We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible and short-term firm transportation services. During 2008, we served a total of 136
transportation and storage customers. Our largest customer was Puget Sound Energy, Inc., which accounted for approximately 20.7 percent of our total operating revenues for the year ended December 31, 2008. No other customer accounted for more than 10 percent of our total operating revenues during that period.
Our rates are subject to the rate-making policies of FERC. We provide a significant portion of our transportation and storage services pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees, which are fees that are owed for reserving an agreed upon amount of pipeline or storage capacity regardless of the amount of pipeline or storage capacity actually utilized by a customer. When a customer utilizes the capacity it has reserved under a firm transportation contract, we also collect a volumetric fee based on the quantity of natural gas transported. These volumetric fees are typically a small percentage of the total fees received under a firm contract. We also derive a small portion of our revenues from short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related services. The high percentage of our revenue derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions.
We have approximately 12.8 Bcf of working natural gas storage capacity through the following three storage facilities. These natural gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to certain major customers.
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Jackson Prairie: We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of our distribution customers. As of December 31, 2008, our share of the firm seasonal storage service in this facility was approximately 7.5 Bcf of working natural gas storage capacity and up to 383 MMcf* per day of peak day deliveries. Additionally, our share of the best-efforts delivery capacity was 50 MMcf per day. As described below, we are participating in an ongoing expansion of Jackson Prairie.
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Plymouth LNG: We also own and operate a Liquid Natural Gas (LNG) storage facility located near Plymouth, Washington, which provides standby service for our customers during extreme peaks in demand. The facility has a total LNG storage capacity equivalent to 2.3 Bcf of working natural gas, liquefaction capability of 12 MMcf per day and regasification capability of 300 MMcf per day. Certain of our major customers own the working natural gas stored at the LNG plant.
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Clay Basin Field: We have a contract with a third party under which we contract for natural gas storage services in an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. We are authorized to utilize the Clay Basin Field at a seasonal storage level of 3.0 Bcf of working natural gas, with a firm delivery capability of 25 MMcf of natural gas per day.
*
The term “Mcf” means thousand cubic feet, “MMcf” means million cubic feet and “Bcf” means billion cubic feet. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. The term “MMBtu” means one million British Thermal Units and “TBtu” means one trillion British Thermal Units. The term “Dth” means one dekatherm, which is equal to one MMBtu. The term “MDth” means thousand dekatherms. The term “MMDth” means million dekatherms.
Competition
We believe the topography of the Pacific Northwest makes construction of competing pipelines difficult and expensive and it forms a natural barrier to entry for potential competitor pipelines in our primary markets such as Seattle, Washington; Portland, Oregon and Boise, Idaho. Our pipeline is currently the sole source of interstate natural gas transportation in many of the markets we serve. However, there are a number of factors that could increase competition in our traditional market area. For example, customers may consider such factors as cost of service and rates, location, reliability, available capacity, flow characteristics, pipeline service offerings, supply abundance and diversity and storage access when analyzing competitive pipeline options.
Competition could arise from new ventures or expanded operations from existing competitors. For example, in late 2006, Northwest Natural Gas Co. (Northwest Natural), our second largest customer, announced that it is partnering with TransCanada’s Gas Transmission Northwest (GTN) to build the
Palomar Gas Transmission project. This proposed project would consist of a greenfield pipeline from GTN’s system in central Oregon to Northwest Natural’s system in western Oregon. Palomar could also be used to transport natural gas from one of the proposed Columbia River LNG terminals back to GTN’s system.
We are also experiencing increased competition for domestic supply with the completion of projects such as Kinder Morgan’s Rockies Express and Wyoming Interstate’s Kanda Lateral, which are designed to transport natural gas produced in the Piceance and Uinta Basins to Midwestern and Eastern markets. El Paso Corporation has proposed a new pipeline project, called Ruby, which would begin at the Opal Hub in Wyoming and terminate in Malin, Oregon, near the California border, to create additional access to Rocky Mountain gas in western markets.
Natural gas also competes with other forms of energy available to Northwest’s customers, including electricity, coal, fuel oils and other alternative energy sources. A shift from natural gas to other forms of energy could cause a decrease in use of our storage and transportation services.
In addition, FERC’s continuing efforts to promote competition in the natural gas industry have increased the number of service options available to shippers in the secondary market. As a result, our customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with our pipeline services. Some customers see this as a benefit because it allows them to effectively reduce the cost of their capacity reservation fees.
Supply and Demand Dynamics
To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in natural gas supply and demand. Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as imported LNG, directly or indirectly affect the demand for our services from both producers and consumers. For example, western U.S. production levels are growing rapidly, but a large portion of the new production of natural gas from the Rocky Mountain region will be delivered to markets in the mid-continent and eastern U.S. through projects like the Rockies Express Pipeline. Canadian production levels, on the other hand, are in a flat to downward trend and exports to U.S. markets are declining. As a result, our customers will face increasing competition from Mid-Continent and East Coast markets for Rocky Mountain natural gas supplies. As these supply dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to customers willing to contract for transportation on a long-term firm basis. Changes in demographics, the amount of electricity generation, prevailing weather conditions and shifts in residential and commercial usage affect our customers’ overall demand for natural gas. As customer demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet their long-term requirements.
Customers
Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies (LDCs), direct industrial users, electric power generators and natural gas marketers and producers. Northwest provides natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Northwest’s customers use our transportation and storage services for a variety of reasons. Natural gas distribution companies and electric generation companies typically require a secure and reliable supply of natural gas over a prolonged period of time to meet the needs of their customers and frequently enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Producers of natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Natural gas marketers use storage and transportation services to capitalize on price differentials over time or between markets. Northwest’s customer mix can vary over time and largely depends on the natural gas supply and demand dynamics in its markets.
CAPITAL PROJECTS
The pipeline projects listed below are significant future pipeline projects for which we have significant customer commitments.
Colorado Hub Connection Project
We have proposed installing a new 27-mile, 24-inch diameter lateral to connect the Meeker/White River Hub near Meeker, Colorado to our mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection (CHC Project). It is estimated that the construction of the CHC Project will cost up to $60 million with service targeted to commence in November 2009. We will combine the lateral capacity with 341 MDth per day of existing mainline capacity from various receipt points for delivery to Ignacio, Colorado, including approximately 98 MDth per day of capacity that was sold on a short-term basis. Approximately 243 MDth per day of this capacity was originally held by Pan-Alberta Gas under a contract that terminates on October 31, 2012.
In addition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub for our on-system and off-system markets. We have entered into precedent agreements with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. In September 2008, we filed an application for FERC certification and are awaiting necessary regulatory approvals. If we do not proceed with the CHC Project, we will seek recovery of any shortfall in annual capacity reservation revenues from our remaining customers in a future rate proceeding. We expect to collect maximum rates for the new CHC Project capacity commitments and seek approval to recover the CHC Project costs in any future rate case filed with the FERC.
Jackson Prairie Underground Expansion
The Jackson Prairie Storage Project, connected to our transmission system near Chehalis, Washington, is operated by Puget Sound Energy and is jointly owned by Puget Sound Energy, Avista Corporation and us. A phased capacity expansion is currently underway and a deliverability expansion was placed in service on November 1, 2008.
As a one-third owner of Jackson Prairie, in early 2006, we held an open season for a new firm storage service based on our 100 MMcf per day share of the planned 2008 deliverability expansion and our approximately 1.2 Bcf share of the working natural gas storage capacity expansion to be developed over approximately a six-year period from 2007 through 2012.
As a result of the open season, four shippers have executed long-term service agreements for the full amount of incremental storage service offered at contract terms averaging 33 years. The firm service relating to storage capacity rights will be phased-in as the expanded working natural gas capacity is developed. Our one-third share of the deliverability expansion was placed in service on November 1, 2008 at a cost of approximately $16.0 million. Our estimated capital cost for the capacity expansion component of the new storage service is $6.1 million, primarily for base natural gas.
Sundance Trail Expansion
In February 2008, we initiated an open season for the proposed Sundance Trail Expansion project that resulted in the execution of an agreement for 150 MDth per day of firm transportation service from the Meeker/White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project will include construction of approximately 16 miles of 30-inch loop between our existing Green River and Muddy Creek compressor stations in Wyoming as well as an upgrade to our existing Vernal compressor station, with service targeted to commence in November 2010. The total project is estimated to cost up to $65 million, including the cost of replacing existing compression at the Vernal compressor station which will enhance the efficiency of our system. The Sundance Trail Expansion will utilize available capacity on the CHC lateral and the existing Piceance lateral in conjunction with available and expanded mainline capacity. The Sundance Trail Expansion remains subject to certain conditions, including receiving the necessary regulatory approvals. We expect to collect our maximum system rates, and will seek approval to roll-in the Sundance Trail Expansion costs in any future rate case filed with the FERC.
OPERATING STATISTICS
Throughput
The following table summarizes volumes and capacity for the periods indicated:
(1)
Parachute Lateral volumes of 102 TBtu in 2008 and 55 TBtu in 2007 are excluded from total throughput as these volumes flow under separate contracts that do not result in mainline throughput.
(2)
Includes additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis.
Seasonality
Although we deliver more gas to our market areas in the winter heating season months of November through March, because a significant percentage of our revenues are collected through reservation fees, our revenues remain fairly stable from quarter to quarter. The table below sets forth seasonal revenues, expenses and throughput for each quarter and the total year ended December 31, 2008.
(1)
Parachute Lateral volumes are excluded from throughput as these volumes flow under separate contracts that do not generally result in mainline throughput.
REGULATORY MATTERS
FERC Regulation
Our interstate pipeline system and storage facilities are subject to extensive regulation by FERC. FERC has jurisdiction with respect to virtually all aspects of our business, including generally:
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transportation and storage of natural gas;
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rates and charges;
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terms of service including creditworthiness requirements;
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construction of new facilities;
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extension or abandonment of service and facilities;
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accounts and records;
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depreciation and amortization policies;
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relationships with gas marketing functions within Williams; and
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initiation and discontinuation of services.
We hold certificates of public convenience and necessity issued by FERC pursuant to Section 7 of the Natural Gas Act of 1938 (NGA) covering our facilities, activities and services. We may not unduly discriminate in providing open access, available transportation and storage services to customers qualifying under our tariff provisions. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of items for regulatory purposes. The books and records of interstate pipelines may be periodically audited by FERC.
FERC regulates the rates and charges for transportation and storage in interstate commerce. Interstate pipelines may not charge rates that have been determined not to be just and reasonable.
The maximum recourse rates that may be charged by interstate pipelines for their services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are level of plant investment and costs of providing service, allowed rate of return and volume throughput, and contractual capacity commitments. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved tariff or established by reference to FERC’s regulations. Rate design and the allocation of costs also can impact a pipeline’s profitability. Interstate pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”
Interstate pipelines may also use “negotiated rates” which, in theory, could involve rates above or below the “recourse rate,” provided the affected customers are willing to agree to such rates. A prerequisite for having the right to agree to negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s maximum recourse rates.
Pursuant to our March 30, 2007 rate settlement, we are required to file a new rate case to be effective not later than January 1, 2013.
FERC Policy Statement on Income Tax Allowances
In May 2005, FERC issued a statement of general policy, permitting a pipeline to include in cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. In June 2005 FERC applied its new policy and granted a partnership owning an oil pipeline an income tax allowance when establishing rates. That decision, applying the new policy to the particular oil pipeline, was appealed to the D.C. Circuit. The D.C. Circuit, by order issued May 29, 2007, denied the appeal and upheld FERC’s new tax allowance policy as applied in the decision involving the oil pipeline on all points subject to the appeal. On August 20, 2007, the D.C. Circuit denied rehearing of its decision.
On December 8, 2006, FERC issued an order in an interstate oil pipeline proceeding addressing its income tax allowance policy, noting that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this creates an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling. On December 26, 2007, FERC issued an order on rehearing affirming its prior ruling. FERC indicated that it will continue to review on a case-by-case basis whether a pipeline’s owners have an actual or potential income tax liability and may
utilize a normalization approach to reduce a pipeline’s income tax allowance as appropriate. On January 25, 2008, shippers on the pipeline asked FERC to reconsider its income tax allowance policy, including whether such allowance should be permitted at all. On February 15, 2008, FERC responded that the shipper’s income tax allowance issues are complex and will be addressed at a later time.
The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. If FERC were to disallow a substantial portion of our income tax allowance, it may be more difficult for us to justify our rates in future proceedings. If we are unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating our cost of service in future rate cases, FERC could disallow a substantial portion of our income tax allowance, and our maximum lawful rates could decrease from current levels.
FERC Policy Statement on Proxy Groups and Return on Equity
In an effort to provide guidance and to obtain public comment on FERC’s policies concerning return on equity determinations, on July 19, 2007, FERC issued a proposed policy statement. In the proposed policy statement, FERC proposed to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings.
After receiving public comment on the proposed policy statement, on April 17, 2008, FERC issued a final policy statement which rejected the concept of capping distributions in favor of an adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly traded partnerships which are included in the proxy group.
On January 19, 2009, FERC applied the policy statement to a pipeline rate case and determined that the pipeline’s equity return should be 11.55 percent. It is difficult to know how instructive this case is for purposes of anticipating rates of return in future rate cases, because FERC determined the composition of the proxy group using data from 2004 when the case was filed.
The effect of the application of FERC’s policy to our future rate proceedings is not certain and we cannot ensure that such application would not adversely affect our ability to achieve a reasonable level of return on equity.
Energy Policy Act of 2005
On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (EP Act 2005). Among other matters, EP Act 2005 amends the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations prescribed by FERC and provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EP Act 2005, and subsequently denied rehearing of that order. The rule makes it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, (i) to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. The EP Act 2005 also amends the NGA and the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.
Safety and Maintenance
We are subject to regulation by the United States Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to the Natural Gas Pipeline Safety Act of 1968 (NGPSA) and the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in high consequence areas. PHMSA regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. The PHMSA may assess fines and penalties for violations of these and other requirements imposed by its regulations.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but some are certified by DOT to assume responsibility for inspection and enforcement of federal natural gas pipeline safety regulations. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Our natural gas pipeline has inspection and compliance programs designed to maintain compliance with federal and applicable state pipeline safety and pollution control requirements.
We are subject to a number of federal laws and regulations, including the federal Occupational Safety and Health Act (OSHA), and some comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the U.S. Environmental Protection Agency 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 operations and that this information be provided to employees, state and local government authorities, and citizens.
Environmental Regulation
General
Our natural gas transportation and storage operations are subject to extensive and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including:
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requiring the acquisition of permits to conduct regulated activities;
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restricting the manner in which we can release materials into the environment;
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imposing investigatory and remedial obligations to mitigate pollution from former or current operations;
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assessing administrative, civil and criminal penalties for failure to comply with applicable legal requirements; and
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in certain instances, enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to applicable laws and regulations.
As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements will not have a material adverse effect on us.
The following is a discussion of some of the environmental laws and regulations that are applicable to natural gas transportation and storage activities and that may have a material impact on our business.
Waste Management
Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that receive these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous solid wastes, which includes certain wastes associated with the exploration and production of oil and natural gas. In the course of our operations, we may generate petroleum hydrocarbon wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous solid wastes. Similarly, the Toxic Substances Control Act (TSCA), and analogous state laws impose requirements on the use, disposal and storage of various chemicals and chemical substances. In the course of our operations, we may use chemicals and chemical substances that are regulated by TSCA.
Site Remediation
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), 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 owner or operator of a site where a hazardous substance was released into the environment, and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that were released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (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 that they incur. 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 currently own or lease properties that for many years have been used for the transportation, compression, and storage of natural gas. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and 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 recycling or disposal. In addition, some of these properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons 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 (i) remove previously disposed wastes, including waste disposed of by prior owners or operators; (ii) remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or (iii) perform remedial closure operations to prevent future contamination.
Air Emissions
The Clean Air Act and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require (i) pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; (ii) application for and strict compliance with air permits containing various emissions and operational limitations; or (iii) the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in the assessment of monetary penalties and the
pursuit of potentially criminal enforcement actions, the issuance of injunctions, and the further imposition of conditions or restrictions on permitted operations.
We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, we may be required to supplement or modify our air emission control equipment and strategies due to changes in state implementation plans for controlling air emissions in regional non-attainment areas, or stricter regulatory requirements for sources of hazardous air pollutants. We believe that any such future requirements imposed on us will not have a material adverse effect on our operations.
Water Discharges
The Federal Water Pollution Control Act (Clean Water Act) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters as well as waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also regulates storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, and monitor and sample storm water runoff from their facilities. Under the Clean Water Act, federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Activities on Federal Lands
Natural gas transportation activities conducted on federal lands are subject to review and assessment under provisions of the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, agencies prepare Environmental Assessments, or more detailed Environmental Impact Statements, that assess the potential direct, indirect and cumulative impacts of a proposed project and which may be made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.
Endangered Species
The Endangered Species Act restricts activities that may affect threatened and endangered species or their habitats. Some of Northwest’s natural gas pipeline is located in areas inhabited by threatened or endangered species. If Northwest’s activities adversely affect endangered species or their habitats, Northwest could incur additional costs or become subject to operating restrictions or bans in the affected area. Civil and criminal penalties can be imposed against any person violating the Endangered Species Act.
INSURANCE
Our insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate. However, we are not fully insured against all risks inherent in our business. See “Risk Factors” below.
EMPLOYEES
As of February 1, 2009, our consolidated affiliate, Northwest Pipeline Services LLC had 426 employees. Northwest has no employees. Services are provided to Northwest by Northwest Pipeline Services LLC, a variable interest entity.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with Williams and other Williams’ subsidiaries. See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 1. Summary of Significant Accounting Policies and Note 8. Transactions with Major Customers and Affiliates and Part III, Item 13. Certain Relationships and Related Transactions and Director Independence.
Item 1A.
Item 1A. RISK FACTORS
FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:
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amounts and nature of future capital expenditures;
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expansion and growth of our business and operations;
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financial condition and liquidity;
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business strategy;
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cash flow from operations or results of operations;
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rate case filings; and
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natural gas and natural gas liquids prices and demand.
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Many of the factors that will determine these results are beyond our ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
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availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and costs of capital;
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inflation, interest rates, and general economic conditions (including the recent economic slowdown and the disruption of global credit markets and the impact of these events on our customers and suppliers);
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the strength and financial resources of our competitors;
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development of alternative energy sources;
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the impact of operational and development hazards;
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costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings;
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our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
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increasing maintenance and construction costs;
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changes in the current geopolitical situation;
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our exposure to the credit risk of our customers;
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risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
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risk associated with future weather conditions;
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acts of terrorism; and
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additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.
Risks Inherent to our Industry and Business
Our natural gas transportation and storage activities involve numerous risks that might result in accidents and other operating risks and hazards.
Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include, but are not limited to:
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fires, blowouts, cratering and explosions;
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uncontrolled releases of natural gas;
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pollution and other environmental risks;
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natural disasters;
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aging pipeline infrastructure and mechanical problems;
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damage inadvertently caused by third party activity, such as operation of construction equipment; and
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terrorist attacks or threatened attacks on our facilities or those of other energy companies.
These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.
Our current pipeline infrastructure is aging, which may adversely affect our business.
Some portions of our pipeline infrastructure are approximately 50 years old. The current age and condition of this pipeline infrastructure could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining our facilities exceed current expectations.
Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.
We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, Williams and its other affiliates, including Williams Partners L.P. and WMZ, are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.
The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets could have the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of, or increase the demand for, natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Please read “Business Competition”. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.
Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Although none of our material contracts are terminable in 2009, upon expiration of the terms we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis.
The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
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the level of existing and new competition to deliver natural gas to our markets;
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the growth in demand for natural gas in our markets;
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whether the market will continue to support long-term firm contracts;
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whether our business strategy continues to be successful;
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the level of competition for natural gas supplies in the production basins serving us; and
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the effects of state regulation on customer contracting practices.
Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.
Our business is dependent on the continued availability of natural gas production and reserves. The development of the additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transmission facilities.
Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas transported and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations.
Decreases in demand for natural gas could adversely affect our business.
Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of
which are matters beyond our control. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our transmission facilities.
Significant prolonged changes in natural gas prices could affect supply and demand and cause a termination of our transportation and storage contracts or a reduction in throughput on our system.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which could expose us to significant costs and liabilities and could exceed our current expectations.
Our natural gas transportation and storage operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. For a description of these laws and regulations, please see “Business - Regulatory Matters - Environmental Regulation.”
These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in the operation of natural gas transportation and storage facilities due to the handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to the operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including the federal Comprehensive Environmental Response, Compensation, and Liability Act the federal Resource Conservation and Recovery Act and analogous state laws, in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of its remedial costs from insurance. Please read “Business - Regulatory Matters - Environmental Regulation” for more information. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly regulated substance and waste handling, storage, transport, disposal, or remedial requirements could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may be subject to legislative and regulatory responses to climate change with which compliance may be costly.
Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and similar federal legislation has been introduced in both houses of the Congress. Our pipeline may be subject to
regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If we are unable to recover all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.
The failure of new sources of natural gas production or LNG import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for our services.
New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future natural gas supplies in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed natural gas prices could increase and cause consumers of natural gas to turn to alternative energy sources which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.
We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2008, our largest customer was Puget Sound Energy, Inc. This customer accounted for approximately 20.7 percent of our operating revenues for the year ended December 31, 2008. The loss of even a portion of our contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. While we monitor these situations carefully and attempt to take appropriate measures to protect ourselves, it is possible that we may have to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our operating results and financial condition
If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable due to repairs, damage to the facility, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or any other reason, our ability to operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing our revenues. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. We obtain, in certain instances, the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We do not have the right of eminent domain over land owned by Native American tribes. Our loss of any of these rights, through our inability to renew right of way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of the insurers we do use to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the aggregate annually and a deductible of $2 million per occurrence. This insurance covers Williams and its affiliates, including us for legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Williams and its affiliates.
Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to assets and resulting business interruption caused by terrorist acts committed by a U.S. person or interest. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina, Rita, Gustav and Ike have impacted the availability of certain types of coverage at reasonable rates, and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any potential claims. As a result, we could be exposed to greater losses than anticipated and replacement insurance may have to be obtained, at a greater cost, if available.
Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.
A significant portion of our growth is accomplished through the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
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the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;
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the availability of skilled labor, equipment, and materials to complete expansion projects;
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potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;
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impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
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the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and
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the ability to access capital markets to fund construction projects.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect results of operations, financial position or cash flows.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB), the SEC or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.
Risks Related to Strategy and Financing
Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.
Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.
Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
Events in the global credit markets created a shortage in the availability of credit and have led to credit market volatility.
In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. While we cannot predict the occurrence of future disruptions or the duration of current volatility in the credit markets, we believe cash on hand and cash provided by operating activities, as well as availability under our existing financing agreements will provide us with adequate liquidity. However, our ability to borrow under our existing financing agreements, including our bank credit facilities, could be negatively impacted if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing volatility or additional disruptions, including the bankruptcy or restructuring of certain financial institutions, may adversely affect the availability of credit already arranged and the availability and cost of credit in the future.
The continuation of recent economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.
The slowdown in the economy and the significant disruptions and volatility in global credit markets have the potential to negatively impact our business in many ways. Included among these potential negative impacts are reduced demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could result in reducing our access to credit markets, raising the cost of such access or requiring us or Williams to provide additional collateral to third parties.
A downgrade of our current credit ratings could impact our liquidity, access to capital and our costs of doing business, and maintaining our current credit ratings is under the control of independent third parties.
A downgrade of our credit rating might increase our cost of borrowing and could cause us to post collateral with third parties, thereby negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:
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economic downturns;
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deteriorating capital market conditions;
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declining market prices for natural gas;
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terrorist attacks or threatened attacks on our facilities or those of other energy companies;
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the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. We are currently rated investment grade by three of the major credit rating agencies; however, no assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.
Williams can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.
Our general partners are both indirectly controlled by Williams. The majority interest in our business is owned by a subsidiary of Williams. As a result, Williams exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:
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decisions on financings and our capital raising activities;
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mergers or other business combinations; and
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acquisition or disposition of assets.
Our majority partner’s board of directors could decide to increase distributions or advances to our partners consistent with existing debt covenants. This could adversely affect our liquidity. Moreover, various Williams’ credit facilities include covenants restricting the ability of Williams’ entities, including us, to make advances to Williams and its other subsidiaries, which could make the terms on which we may be able to secure additional future financing less favorable.
The financial condition and liquidity of Williams affects our access to capital, our credit standing and our financial condition.
Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries, including WGP, our majority partner, under which Williams’ interstate natural gas pipelines and gas pipeline joint venture investments are grouped. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.
Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience a deterioration in its credit standing or financial difficulties, our access to credit and our ratings could be adversely affected.
Risks Related to Regulations that Affect our Industry
Our natural gas transportation and storage operations are subject to regulation by FERC, 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 pipeline, including a reasonable return.
Our interstate natural gas transportation and storage operations are subject to federal, state and local regulatory authorities. Specifically, our interstate transportation and storage services and related assets are subject to regulation by FERC. The federal regulation extends to such matters as:
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transportation of natural gas in interstate commerce;
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rates, operating terms and conditions of service;
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the types of services we may offer to our customers, including initiation and discontinuation of services;
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certification and construction of new facilities;
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acquisition, extension, disposition or abandonment of facilities;
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accounts and records;
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depreciation and amortization policies;
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relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and
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market manipulation in connection with interstate sales, purchases or transportation of natural gas.
Under the Natural Gas Act, FERC has authority to regulate interstate providers of natural gas pipeline transportation and storage services, and such providers may only charge rates that have been determined to be just and reasonable by FERC. In addition, FERC prohibits providers from unduly
preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.
The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from marketing function employees and by restricting the information that transmission providers may provide to gas marketing employees. The inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of the rules are subject to potentially substantial civil penalty assessments.
The rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC-approved tariff. Pursuant to the terms of our most recent rate settlement agreement, we and the other parties to the settlement are precluded from filing for any further increases or decreases in existing rates prior to January 1, 2009 and we must file a new rate case to become effective not later than January 1, 2013. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation and storage services.
We could be subject to penalties and fines if we fail to comply with FERC regulations.
Our transportation and storage operations are regulated by FERC. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on our business, financial condition, results of operations and cash flows.
The outcome of future rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.
There is a risk that rates set by the FERC will be inadequate to cover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.
Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.
Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which we or our affiliates are named as defendants. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.
Certain inquiries, investigations and court proceedings are ongoing. We might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, disputes over gas measurement and royalty payments, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology.
Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.
In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
Failure of or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.
Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
Our costs and funding obligations for defined benefit pension plans and costs for other postretirement benefit plans, in which we participate, are affected by factors beyond our control.
We are a participating employer in defined benefit pension plans covering substantially all of our U.S. employees and other postretirement benefit plans covering certain eligible participants. The timing and amount of our funding allocation requirements under the defined benefit pension plans in which we participate depend upon a number of factors Williams controls, including changes to pension plan benefits as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding allocation requirements could have a significant adverse effect on our financial condition. The amount of expenses recorded for the defined benefit pension plans and other postretirement benefit plans, in which we participate, is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact our future results of operations.
Risks Related to Weather, Other Natural Phenomena and Business Disruption
Our assets and operations can be affected by weather and other natural phenomena.
Our assets and operations can be adversely affected by earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is
impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 2.
Item 2. PROPERTIES
We own our system in fee simple. However, a substantial portion of our system is constructed and maintained on and across properties owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our compressor stations, with associated facilities, are located in whole or in part upon lands owned by us and upon sites held under leases or permits issued or approved by public authorities. Land owned by others, but used by us under rights-of-way, easements, permits, leases, licenses or consents includes land owned by private parties, federal, state and local governments, quasi-governmental agencies, or Native American tribes. The Plymouth LNG facility is located on lands owned in fee simple by us. Various credit arrangements restrict the sale or disposal of a major portion of our pipeline system. We lease our corporate offices in Salt Lake City, Utah.
Item 3.
Item 3. LEGAL PROCEEDINGS
The information called for by this item is provided in Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 3. Contingent Liabilities and Commitments - Legal Proceedings.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
Item 5.
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of December 31, 2007, we were wholly-owned by Williams. As of December 31, 2008, we are owned 65 percent by Williams and 35 percent by Williams Pipeline Partners L.P., a publicly traded master limited partnership. Our partnership interest is not publicly traded. Through its partial ownership of Williams Pipeline Partners L.P., Williams directly and indirectly owns 81.7 percent of us.
We paid $419.3 million and $109.8 million in cash distributions to our partners during 2008 and 2007, respectively.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The following financial data should be read in conjunction with Part II, Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Unless indicated otherwise, the following discussion of critical accounting policies and estimates, discussion and analysis of results of operations, and financial condition and liquidity should be read in conjunction with the financial statements and notes thereto included within Part II, Item 8 of this report.
HOW WE EVALUATE OUR OPERATIONS
We evaluate our business on the basis of a few key measures:
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the level of capacity reserved under our long-term firm transportation and storage contracts;
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the level of revenues provided by our short-term firm and interruptible transportation and storage services;
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our operating expenses; and
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our cash available for distribution.
Long-Term Firm Service
We compete for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. To the extent our customers believe that we can offer these services at rates, terms and conditions that are more attractive than those of our competition, they will be more inclined to purchase our services. Firm transportation service requires us to reserve pipeline capacity for a customer at certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” charge based on the amount of capacity being reserved regardless of whether the capacity is used, plus a volumetric fee and an in-kind fuel reimbursement based on the volume of natural gas transported. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, and generally pay a capacity reservation charge based on the amount of capacity reserved. Capacity reservation revenues derived from long-term firm service contracts generally remain constant over the term of the contracts, subject to adjustment in rate proceedings with FERC, because the revenues are primarily based upon the capacity reserved and not whether the capacity is actually used. Our ability to maintain or increase the amount of long-term firm service we provide is key to assuring a consistent revenue stream.
Short-Term Firm and Interruptible Service
A small portion of our revenues are generated by short-term firm and interruptible services under which customers pay fees for transportation, storage or other related services. Of our revenues for the twelve months ended December 31, 2008, approximately 5.7 percent were derived from short-term firm and interruptible services.
Operating Expenses
Our operating expenses typically do not vary significantly based upon the amount of natural gas we transport. While expenses may not materially vary with throughput, the timing of our spending during a year can be dictated by weather and customer demands. During the winter months, our pipeline average throughput is higher. As a result, we typically do not perform compressor or pipeline maintenance until off-peak periods, which generally results in higher costs in the second and third quarters compared to the other two quarters. We are also regulated by the federal government and certain state and local laws which can impact the activities we perform on our pipeline. Changes in these regulations or our assessment of the condition of inspected facilities can increase costs. As an example, the Pipeline Safety Improvement Act of 2002 set new standards for pipelines in assessing the safety and reliability of their pipeline infrastructure. We and other pipelines have incurred additional costs to meet these standards. Certain of our markets are served by other interstate natural gas pipelines and we need to operate our system efficiently and reliably to effectively compete for transportation and storage services.
Cash Available for Distribution
Under our general partnership agreement, on or before the end of the calendar month following each quarter, our management committee is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the
management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.
FACTORS THAT IMPACT OUR BUSINESS
The high percentage of our revenues derived from capacity reservation fees on long-term, contractual arrangements helps mitigate the risk of revenue fluctuations due to near-term changes in natural gas supply and demand conditions and price volatility. Our business can, however, be negatively affected by sustained downturns or sluggishness in the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by our customers, competition and changes in regulatory requirements affecting our operations.
We believe the key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate, our customers and their requirements, and government regulation of natural gas pipelines. These key factors, described in Item 1. Business - Pipeline System, Customers and Competition, play an important role in how we manage our operations and implement our long-term strategies.
We believe the collective impact of these key factors may result in an increasingly competitive natural gas transportation market. This could result in a reduction in the overall average life of our long-term firm contracts which could adversely affect our revenue over the long term. We also believe the impact of such factors may provide us with growth opportunities. These factors may also result in a need for increased capital expenditures to take advantage of opportunities to bring additional supplies of natural gas into our system to maintain or possibly increase our transportation commitments and volumes.
See Part 1, Item 1. Business - Pipeline System, Customers and Competition for a discussion regarding the impact of customers, competition and regulation on our business.
OPERATIONS
We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2008, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 Bcf of natural gas per day. We also have approximately 12.8 Bcf of working natural gas storage capacity through our one-third interest in the Jackson Prairie underground storage facility, our ownership of the Plymouth LNG storage facility and contract storage at Clay Basin.
Transportation Services
Our transportation services consist primarily of a) firm transportation under long-term contracts, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points on the system, plus a volumetric fee and an in-kind fuel reimbursement based on the volume transported; and b) interruptible transportation, whereby the customer pays to transport natural gas when capacity is available and used. Firm transportation capacity reservation revenues typically do not vary over the term of the contract, subject to adjustment in rate proceedings with FERC, because the revenues are primarily based upon the capacity reserved, and not upon the capacity actually used. We generate a small portion of our revenues from short-term firm and interruptible transportation services.
We are not generally in the business of buying and selling natural gas, but changes in the price of natural gas can affect the overall supply and demand for natural gas, which in turn can affect our results of operations. We depend on the availability of competitively priced natural gas supplies which our customers desire to ship through our system. We deliver natural gas for a broad mix of customers including LDCs municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers.
Storage Services
Our natural gas storage services allow us to offer customers a high degree of flexibility in meeting their delivery requirements and enable us to balance daily receipts and deliveries. For example, LDCs use traditional storage services by injecting natural gas into storage in the summer months when natural gas prices are typically lower and then withdrawing the natural gas during the winter months in order to reduce their exposure to the potential volatility of winter natural gas prices. We offer firm storage service, in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage service, where the customer receives and pays for capacity only when it is available and used.
RECENT MARKET EVENTS
The recent instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. In this volatile economic environment, many financial markets, institutions and other businesses remain under considerable stress. These events are impacting our business. However, we note the following:
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We have no significant debt maturities until 2016.
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As of December 31, 2008, we have approximately $66.0 million of available cash from return of advances made to affiliates and available capacity under our Credit Facility. (See further discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations - Method of Financing.)
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A significant portion of our transportation and storage services are provided pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees regardless of the amount of pipeline or storage capacity actually utilized by a customer.
OUTLOOK
Our strategy to create value focuses on maximizing the contracted capacity on our pipeline by providing high quality, low cost natural gas transportation and storage services to our markets. Changes in commodity prices and volumes transported have little impact on revenues because the majority of our revenues are recovered through firm capacity reservation charges. We grow our business primarily through expansion projects that are designed to increase our access to natural gas supplies and to serve the demand growth in our markets. See Part 1, Item 1. Business - Capital Projects.
The overall decline in the equity markets in 2008 negatively impacted the Williams employee benefit plan assets and will increase our net periodic benefit expense in future periods. (See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 5. Employee Benefit Plans.)
CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS AND SENSITIVITIES
The accounting policies discussed below are considered by our management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment.
Regulatory Accounting
See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 1. Summary of Significant Accounting Policies - Property, Plant and Equipment and Note 10. Regulatory Assets and Liabilities.
Contingencies
We record liabilities for estimated loss contingencies when a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the
period in which different facts or information become known or circumstances change that affect previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon management’s assumptions and estimates regarding the probable outcomes of the matters. Should the outcomes differ from the assumptions and estimates, revisions to the liabilities for contingent losses would be required.
Environmental Liabilities
Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and independent consultants, and the current facts and circumstances related to these environmental matters. Our accrued environmental liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, the FERC and other governmental authorities on these matters. We continue to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the total estimated environmental costs.
Pension and Postretirement Obligations
We participate in employee benefit plans with Williams and its subsidiaries that include pension and other postretirement benefits. Net periodic benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.
RESULTS OF OPERATIONS
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 2008, 2007 and 2006. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.
Years Ended December 31, 2007 and 2008
Operating revenues increased $13.0 million, or 3 percent, for the year ended December 31, 2008 as compared to the year ended December 31, 2007. This increase is attributed to a $3.9 million increase from the Parachute Lateral, placed into service in May 2007, and a $5.2 million increase from short-term firm transportation services, with the balance of the increase primarily attributed to certain small customers converting to large customer status resulting in higher reservation charges and to higher transportation volumes.
Our transportation service accounted for 96 percent of our operating revenues for each of the years ended December 31, 2008 and 2007. Natural gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2008 and 2007.
Operating expenses increased $22.6 million, or 11 percent, from 2007 to 2008. This increase is due primarily to the June 2007 reversal of our pension regulatory liability of $16.6 million as described in Note 1 of the Notes to Consolidated Financial Statements, and the new Parachute Lateral lease of $10.1 million, which began January 1, 2008. Also contributing were higher use taxes of $1.0 million attributed primarily to the 2007 reversal of $0.8 million of accrued use taxes resulting from the settlement of prior year audits, and higher depreciation of $1.5 million and ad valorem taxes of $1.6 million resulting from property additions. These increases were partially offset by lower expenses of $5.0 million for contracted services attributed primarily to pipeline maintenance, lower overhead allocated by Williams of $2.0 million and lower
bonus accruals and deferred compensation of $1.0 million primarily attributed to lower bonus and deferred compensation levels in 2008.
Operating income decreased $9.6 million, or 5 percent, from 2007 to 2008, due to the reasons discussed above.
Other income decreased $23.8 million, or 94 percent, from 2007 to 2008, primarily due to the recognition in 2007 of $6.0 million of previously deferred income, the receipt of $12.2 million additional contract termination income, and $2.3 million additional interest related to the termination of the Grays Harbor transportation agreement. Also contributing to this decrease were a $2.2 million decrease in interest income from affiliates resulting primarily from lower interest rates and a $2.3 million decrease in the allowance for equity funds used during construction (EAFUDC) resulting from the lower capital expenditures in 2008 and the discontinuance of EAFUDC gross-ups after our conversion to a partnership on October 1, 2007. These decreases were partially offset by the $1.3 million write-off of a regulatory asset associated with the Parachute Lateral in 2007.
Interest charges decreased $3.7 million, or 7 percent, from 2007 to 2008, due primarily to the April 2007 early retirement of $175.0 million of 8.125 percent senior unsecured notes, the December 2007 refinancing of $250.0 million of 6.625 percent senior unsecured notes with $250.0 million revolver debt at lower interest rates, and the May 2008 refinancing of the $250.0 million revolver debt with the issuance of $250.0 million of 6.05 percent senior unsecured notes. This decrease was partially offset by the April 2007 issuance of $185.0 million of 5.95 percent senior unsecured notes and a $0.9 million decrease in the allowance for borrowed funds used during construction resulting from lower capital expenditures in 2008.
The benefit for income taxes decreased $254.7 million to $0 from 2007 to 2008 due to our conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, we recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8 percent. At the date of conversion, we recognized income tax benefit of $311.8 million reflecting the removal of our net deferred tax liabilities.
Years Ended December 31, 2006 and 2007
Operating revenues increased $97.6 million, or 30 percent, for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Higher rates resulting from our rate case, which became effective January 1, 2007, were the primary reason for this increase. In addition, the Parachute Lateral, placed into service in May 2007, contributed $6.6 million to revenues.
Our transportation service accounted for 96 percent of our operating revenues for each of the years ended December 31, 2007 and 2006. Natural gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2007 and 2006.
Operating expenses decreased $1.1 million, or 1 percent, from 2006 to 2007. This decrease was due primarily to the June 2007 reversal of our pension regulatory liability of $16.6 million and a reduction of accrued ad valorem taxes of $1.0 million to reflect lower 2007 tax assessments on our property. The pension regulatory liability was reversed based upon management’s assessment that the refundability of this obligation in future rates is no longer probable. These decreases were partially offset by a $6.3 million increase in lease expense due to a change in accounting for our headquarters building lease in the fourth quarter of 2006, a $3.7 million increase in depreciation related to new property additions, a $1.5 million write-off of a regulatory asset associated with the Parachute Lateral, a $4.2 million increase in labor costs due to annual salary increases and an increase in the number of employees, and a $1.3 million increase in group insurance expense due primarily to rising medical costs.
Operating income increased $98.7 million, or 88 percent, from 2006 to 2007, due to the reasons discussed above.
Other income increased $8.8 million, or 53 percent, from 2006 to 2007, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million additional contract termination income and $2.3 million additional interest related to the termination of the Grays Harbor transportation agreement. These increases were partially offset by a $5.6 million decrease in the allowance for EAFUDC resulting from lower capital expenditures in 2007, the $1.3 million write-off of a regulatory asset associated with the Parachute Lateral, a $3.1 million decrease in other interest income resulting from
a reduced amount of short-term investments, and a $0.9 million decrease in interest income from affiliates resulting from note repayments from Williams.
Interest charges increased $8.2 million, or 19 percent, from 2006 to 2007, due to a $3.3 million decrease in the allowance for borrowed funds used during construction related to the lower capital expenditures in 2007, the issuance of $175 million of 7 percent senior unsecured notes, due 2016, in June of 2006, and the issuance of $185 million of 5.95 percent senior unsecured notes, due 2017, in April of 2007, partially offset by the early retirement of $175 million of 8.125 percent senior unsecured notes, due 2010, in April of 2007. A $1.8 million increase in other interest resulting from higher amortization of loss on reacquired debt related to the early debt retirement and the refinancing of $250 million of 6.625 percent senior unsecured notes with $250 million of revolver debt in December of 2007 also contributed to this increase.
The provision for income taxes decreased $285.9 million from 2006 to 2007, due to our conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, we recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8 percent compared to 36.4 percent in 2006. At the date of conversion, we recognized income tax benefit of $311.8 million reflecting the removal of our net deferred tax liabilities.
CAPITAL RESOURCES AND LIQUIDITY
Our ability to finance operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness, or to meet collateral requirements, will depend on our ability to generate cash in the future and to borrow funds. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including the impact of regulators on our ability to establish transportation and storage rates.
On or before the end of the calendar month following each quarter, available cash is distributed to our partners as required by our general partnership agreement. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement. During 2008, we distributed $419.3 million of available cash to our partners.
We fund our capital requirements with cash from operating activities, with third party debt or with contributions from our partners with the exception of the CHC Project, which will be funded by capital contributions from Williams.
SOURCES (USES) OF CASH
Operating Activities
Our net cash provided by operating activities in 2008 increased from 2007 due primarily to the increase in our cash operating results, offset by the absence of the receipt of contract termination proceeds of $14.5 million in 2007, and from changes in working capital.
Our net cash provided by operating activities in 2007 increased from 2006 due primarily to the increase in our operating results, including the receipt of contract termination proceeds of $14.5 million, and from changes in working capital.
Financing Activities
Investing Activities
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Capital expenditures totaled $78.6 million primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility.
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We advanced $26.9 million to Williams.
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Capital expenditures totaled $157.2 million primarily related to normal maintenance and compliance.
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We received $79.8 million of proceeds from the sale of the Parachute Lateral to an affiliate.
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We received $10.9 million repayment of advances made to Williams.
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Capital expenditures totaled $473.6 million primarily related to the capacity replacement project.
METHOD OF FINANCING
Working Capital
Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.
Changes in the terms of our transportation and storage arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.
During 2008, we made distributions of available cash of $419.3 million to our partners, representing cash in excess of working capital requirements and reserves established by the management committee as necessary for the conduct of our business.
Short-Term Liquidity
We fund our working capital and capital requirements with cash flows from operating activities, and, if required, borrowings under the Williams credit agreement (described below) and return of advances made to Williams.
We invest cash through participation in Williams’ cash management program. At December 31, 2008 and 2007, the advances due to us by Williams totaled approximately $66.0 million and $39.1 million, respectively. The advances are represented by one or more demand obligations. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately zero percent at December 31, 2008.
Credit Agreement
Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012 (Credit Facility). We have access to $400 million under the agreement to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $71 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2008. In December 2007, we borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250 million was repaid with proceeds from the issuance of $250 million of 6.05 percent senior unsecured notes due 2018. We did not borrow under the agreement in 2008.
Lehman Commercial Paper Inc., which was committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction. See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements.
The Credit Facility contains a number of restrictions on the business of the borrowers, including us. These restrictions include restrictions on the borrowers’ and their subsidiaries’ ability to: (i) grant liens securing indebtedness; (ii) merge, consolidate, or sell, lease or otherwise transfer assets; (iii) incur indebtedness; and (iv) engage in transactions with related parties. We and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in our case, and 0.65 to 1, in the case of Williams. The credit agreement also contains affirmative covenants and events of default. If any borrower breaches financial or certain other covenants or if an event of default occurs, the lenders may cause the acceleration of the borrower’s indebtedness and may terminate lending to all borrowers under the credit agreement. Additionally, if: (a) a borrower were to generally not pay its debts as such debts come due or admit in writing its inability to pay its debts generally; (b) a borrower were to make a general assignment for the benefit of its creditors; or (c) proceedings relating to the bankruptcy or receivership of any borrower were to remain unstayed or undismissed for 60 days, then all lending under the credit agreement would terminate and all indebtedness outstanding under the credit agreement would be accelerated.
Long-Term Financing
Our shelf registration statement on file with the SEC expired on December 1, 2008. We may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. Historically we have been able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements, when needed. However, as a result of credit market conditions, this source of funding is considered economically unfavorable at December 31, 2008.
CAPITAL REQUIREMENTS
The transmission and storage business can be capital intensive, requiring significant investment to maintain and upgrade existing facilities and construct new facilities.
We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 2009 capital expenditures will be between $125 million and $160 million. Of this total, $100 million to $135 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2009, we expect to fund our capital expenditures with cash from operations and repayment of advances to affiliate, with the exception of the CHC Project which will be funded by capital contributions from Williams.
Our expenditures for property, plant and equipment additions were $78.6 million, $157.2 million and $473.6 million for 2008, 2007 and 2006, respectively. The decrease in expenditures from 2006 to 2007 was primarily due to the completion of the Capacity Replacement Project in late 2006. We filed a rate case on June 30, 2006 to recover the cost of property, plant and equipment placed into service as of December 31, 2006. Our new rates became effective January 1, 2007.
CREDIT RATINGS
During 2008, the credit ratings on our senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below.
At December 31, 2008 and through the date of this report, the evaluation of our credit rating is “stable outlook” from Standard and Poor’s. On November 6, 2008, Moody’s Investors Service (“Moody’s”) and Fitch Ratings (“Fitch”) changed the ratings outlook for Williams and each of Williams’ rated subsidiaries, including us, to “negative” and “evolving”, respectively. On February 23, 2009, Moody’s revised our ratings outlook to “stable” from “negative”, and on February 24, 2009, Fitch revised our ratings outlook to “stable” from “evolving.”
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.
With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet
financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
OTHER
Contractual Obligations
The table below summarizes the maturity dates of our more significant contractual obligations and commitments as of December 31, 2008 (in millions of dollars).
(1)
Does not include estimated contributions to the pension and other postretirement benefit plans. We made contributions to the pension and other postretirement benefit plans of $7.8 million in 2008, $3.2 million in 2007 and $5.7 million in 2006. (See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 5. Employee Benefit Plans.) The 2008 economic downturn resulted in a significant decrease in the funded status of the Williams sponsored tax-qualified pension plans. As a result, we anticipate that future contributions to these pension plans may vary significantly from historical contributions if investment returns do not return the expected levels. Future contributions may also be impacted if actual results differ significantly from estimated results or assumptions such as interest rates, retirement rates, mortality and other significant assumptions or by changes to current legislation and regulations.
(2)
Does not include estimated settlement of asset retirement obligations. (See Item 8 Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 9. Asset Retirement Obligations.)
(3)
Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. (See Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 10. Regulatory Assets and Liabilities.)
Off-Balance Sheet Arrangements
We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or our credit ratings.
Impact of Inflation
We have generally experienced increased costs in recent years due to the effect of inflation on the cost of labor, benefits, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies costs can directly affect income through increased operating and maintenance costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of the costs related to our property, plant and equipment and materials and supplies is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, we believe we may be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. However, cost-based regulation along with competition and other market factors limit our ability to price services or products to ensure recovery of inflation’s effect on costs.
Environmental Matters
As discussed in Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 3. Contingent Liabilities and Commitments, we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.
Safety Matters
Please see Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: Note 3. Contingent Liabilities and Commitments for information about pipeline integrity regulations.
Legal Matters
We are party to various legal actions arising in the normal course of business. Our management believes that the disposition of outstanding legal actions will not have a material adverse impact on our future financial condition.
Regulatory Proceedings
Please see Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements: 3. Contingent Liabilities and Commitments for information about regulatory and business developments which cause operating and financial uncertainties.
CONCLUSION
Although no assurances can be given, we currently believe that the aggregate of cash flows from operating activities, supplemented, when necessary, by advances or capital contributions from our partners and from borrowings under the credit agreement, will provide us with sufficient liquidity to meet our capital requirements. Historically, we have been able to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements, when needed. However, as a result of credit market conditions, this source of funding is considered economically unfavorable at December 31, 2008.
Item 7A.
Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Our interest rate risk exposure is limited to our long-term debt. All of our interest on long-term debt is fixed in nature, except the interest on our revolver borrowings, as shown on the following table (in thousands of dollars):
Our total long-term debt at December 31, 2008 had a carrying value of $693.2 million and a fair market value of $572.0 million. As of December 31, 2008, the weighted-average interest rate on our long-term debt was 6.4 percent. We expect to have sensitivity to interest rate changes with respect to future debt facilities and our ability to prepay existing facilities.
Credit Risk
We are exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables and unbilled revenue for services provided, as well as volumes owed by customers for imbalances of natural gas lent by us to them generally under our parking and lending services and no-notice services. We maintain credit policies intended to minimize credit risk and actively monitor these policies.
Market Risk
Our primary exposure to market risk occurs at the time the primary terms of existing transportation and storage contracts expire and are subject to termination. Upon expiration of the primary terms, our contracts generally continue on a year to year basis, but are subject to termination by our customers. In the event of termination, we may not be able to obtain replacement contracts at favorable rates or on a long-term basis.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, our internal control over financial reporting was effective.
This annual report does not include an attestation report of Northwest’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by Northwest’s registered public accounting firm pursuant to temporary rules of the SEC that permit Northwest to provide only management’s report in this annual report.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Management Committee of Northwest Pipeline GP
We have audited the accompanying consolidated balance sheets of Northwest Pipeline GP as of December 31, 2008 and 2007 and the related consolidated statements of income, comprehensive income, owners’ equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Northwest Pipeline GP at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/S/ ERNST & YOUNG LLP
Houston, Texas
February 23, 2009
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CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
See accompanying notes.
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CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
See accompanying notes.
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CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
See accompanying notes.
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CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY
(Thousands of Dollars, Except Per Share Amounts)
See accompanying notes.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)
See accompanying notes.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
See accompanying notes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate Structure and Control
On October 1, 2007, Northwest Pipeline Corporation converted from a Delaware corporation to a general partnership, Northwest Pipeline GP. Northwest Pipeline Corporation, prior to October 1, 2007, and Northwest Pipeline GP, subsequent to September 30, 2007, are hereinafter referred to as “Northwest”. Coincident with the conversion, the partners of Northwest entered into a partnership agreement. Northwest is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986) or enhances operations that generate such qualified income. Because of our conversion to a general partnership, we will no longer be subject to federal and state income taxes. On October 1, 2007, we reversed deferred income tax liabilities of approximately $311.8 million to income and $10.2 million of deferred income tax assets to other comprehensive income.
On January 24, 2008, Williams Pipeline Partners L.P. (WMZ) (previously a wholly-owned subsidiary of The Williams Companies, Inc. (Williams)) completed its initial public offering of limited partnership units, the net proceeds of which were used to acquire a 15.9 percent interest in Northwest. Williams contributed 19.1 percent of its ownership in Northwest in return for limited and general partnership interests in WMZ. Northwest received net proceeds of $300.9 million on January 24, 2008 from WMZ for the purchase of its 15.9 percent interest, and Northwest in turn made a distribution to Williams of $300.9 million. After these transactions, Northwest is owned 35 percent by WMZ and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of Williams. Through its ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of Northwest as of February 26, 2009.
Concurrent with the conversion to a general partnership, Northwest Pipeline Corporation ceased to be an employer. Employees previously employed by Northwest Pipeline Corporation became employees of Northwest Pipeline Services LLC, a consolidated affiliate. Northwest and Northwest Pipeline Services LLC entered into an agreement whereby the employees of Northwest Pipeline Services LLC provide services to Northwest. Northwest reimburses Northwest Pipeline Services LLC for the costs of the employees including compensation and employee benefit plan costs and all related administrative costs.
In this report, Northwest and its consolidated affiliate are at times referred to in the first person as “we”, “us” or “our”.
Nature of Operations
We own and operate an interstate pipeline system for the mainline transmission of natural gas. This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington.
Regulatory Accounting
Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. From time to time, certain revenues collected may be subject to possible refunds upon final FERC orders. Accordingly, estimates of rate refund reserves are recorded considering third-party regulatory proceedings, advice of counsel, our estimated risk-adjusted total exposure, market circumstances and other risks. Our current rates were approved pursuant to a rate settlement. As a result, our current revenues are not subject to refund.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” requires rate-regulated public utilities that apply this standard to account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying SFAS No. 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. At December 31, 2008 and 2007, we had approximately $57.8 million and $54.3 million, respectively, of regulatory assets primarily related to equity funds used during construction, levelized incremental depreciation, asset retirement obligations, environmental costs and other post-employment benefits, and approximately $2.9 million and $17.8 million, respectively, of regulatory liabilities related to postretirement benefits and asset retirement obligations included on the accompanying Balance Sheet.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of Northwest and Northwest Pipeline Services LLC, a variable interest entity for which Northwest is the primary beneficiary.
Our 1983 acquisition by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to our assets and liabilities, based on their estimated fair values at the time of the acquisition. We have elected to include Williams’ purchase price allocations in our financial statements.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; 5) pension and other post-employment benefits; and 6) asset retirement obligations.
Property, Plant and Equipment
Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost. We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation.
Depreciation is provided by the straight-line method by class of assets for property, plant and equipment. The annual weighted average composite depreciation rate recorded for transmission and storage plant was 2.79 percent, 2.76 percent and 2.86 percent for 2008, 2007 and 2006, respectively, including an allowance for negative salvage.
The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project created a revenue stream that will remain constant over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. FERC has approved the accounting for the differences between book depreciation and the Evergreen
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expansion Project’s levelized depreciation as a regulatory asset with the offsetting credit recorded to a regulatory credit on the accompanying Income Statement.
We recorded regulatory credits totaling $2.6 million in 2008, $3.7 million in 2007, and $4.5 million in 2006 in the accompanying Statements of Income. These credits relate primarily to the levelized depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related regulatory assets of $28.4 million at December 31, 2008, and $25.8 million at December 31, 2007. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset with the offset to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates beginning January 1, 2007, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2008 and 2007 were $26.8 million and $21.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.
The negative salvage component of accumulated depreciation ($25.6 million and $21.8 million at December 31, 2008 and 2007, respectively) was reclassified to a noncurrent regulatory asset or liability and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.
Allowance for Borrowed and Equity Funds Used During Construction
Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC is recorded as a reduction in interest expense. The equity funds portion of AFUDC is included in Other Income - net.
The composite rate used to capitalize AFUDC was approximately 9 percent for 2008 and 2007 and approximately 10 percent for 2006. Equity AFUDC of $0.8 million, $2.1 million and $8.9 million for 2008, 2007 and 2006, respectively, is reflected in Other Income - net.
Regulatory Allowance for Equity Funds Used During Construction
Prior to our conversion to a general partnership on October 1, 2007, we recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Since we are no longer subject to income tax following the conversion, we will not record any further additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.
Advances to Affiliates
As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. The advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectibility is reasonably assured. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was zero percent at December 31, 2008.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accounts Receivable and Allowance for Doubtful Receivables
Accounts receivable are stated at the historical carrying amount net of allowance for doubtful accounts. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. As a result, receivables determined to be uncollectible are reserved or written off in the period of such determination.
Materials and Supplies Inventory
All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.
We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline.
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
Income Taxes
Williams and its wholly-owned subsidiaries file a consolidated federal income tax return. It is Williams’ policy to charge or credit its taxable subsidiaries with an amount equivalent to their federal income tax expense or benefit computed as if each subsidiary had filed a separate return.
Through September 30, 2007, we used the liability method of accounting for income taxes which required, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. (See Note 6.)
Deferred Charges
We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment and recovery for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash and Cash Equivalents
Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have an original maturity of three months or less.
Revenue Recognition
Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a demand charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for demand charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is scheduled to be delivered at the agreed upon delivery point or when the natural gas is scheduled to be injected or withdrawn from the storage facility.
In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The exchange gas offset represents the gas balance in our system representing the difference between the exchange gas due to us from customers and the exchange gas that we owe to customers. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in the Platts “Gas Daily Price Guide.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.
As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. At December 31, 2008, we had no rate refund liabilities.
Environmental Matters
We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. If capitalized, such amounts are amortized to expense consistent with the recovery of such costs in our rates. We believe that, with respect to any expenditures required to meet applicable standards and regulations, FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.
Interest Payments
Cash payments for interest were $43.1 million, $49.7 million and $43.5 million in 2008, 2007 and 2006, respectively.
Recent Accounting Standards
In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2008, we adopted SFAS 157. We had no assets or liabilities measured at fair value on a recurring basis. Therefore, the initial adoption of SFAS 157 had no impact on our Consolidated Financial Statements. Beginning January 1, 2009, we will prospectively apply SFAS 157 fair value measurement guidance to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis when such fair value measurements are required. Had we not elected to defer portions of SFAS No. 157, fair value measurement for nonfinancial items would have been applied to the initial measurement at fair value of asset retirement obligations in 2008.
Change in Accounting Estimate
In the second quarter of 2007, we recorded $16.6 million in income for a change in accounting estimate related to a pension regulatory liability. For the tax-qualified pension plans, we had historically recorded a regulatory asset or liability for the difference between pension expense as estimated under SFAS No. 87, “Employer’s Accounting for Pensions” (SFAS No. 87), and the amount we funded as a contribution to our pension plans. As a result of additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.
Reclassifications and Adjustments
In the third quarter of 2006, we made an adjustment to correct an error resulting from an analysis of our regulatory assets. Property, plant and equipment includes the capitalization of equity funds used during construction (EAFUDC). Prior to our conversion to a partnership, the capitalization of EAFUDC created a deferred tax liability and an associated regulatory asset. The regulatory asset was not properly reduced for certain retirements of property, plant and equipment made prior to 2000. The correction of the error resulted in a decrease to miscellaneous other income of $4.7 million and a decrease to net income of $3.0 million during 2006.
In the fourth quarter of 2006, we made adjustments to correct errors related to the accounting for our headquarters building lease expense and depreciation of leasehold improvements. The correction of the errors resulted in a decrease to general and administrative expense of $6.2 million, an increase to depreciation expense of $2.9 million and an increase to Net Income of $2.1 million during 2006.
2. RATE AND REGULATORY MATTERS
Parachute Lateral Project
We placed our Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, we filed an application with the FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (Parachute), which is owned by an affiliate of Williams. This application was approved by the FERC on November 15, 2007, and we completed the transfer of the Parachute Lateral on December 31, 2007. We received cash proceeds of $79.8 million from Parachute equal to the net book value of the net assets transferred, and subsequently made a distribution to Williams in an equal amount. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. Prior to the transfer of the facilities, we reassessed the probability of recovering certain regulatory assets associated with the Parachute Lateral and concluded that with the change of ownership it was not probable that these assets would be recovered in future rates. In the fourth quarter 2007, $2.8 million of these assets were charged to expense.
As contemplated in the application for amendment, Parachute has leased the facilities back to us. We will continue to operate the facilities under the FERC certificate. When Williams Field Services Company, LLC completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate, and Parachute will assume full operational control and responsibility for the Parachute Lateral. Under the terms of the lease, we pay Parachute monthly rent equal to the revenues
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral.
3. CONTINGENT LIABILITIES AND COMMITMENTS
Legal Proceedings
In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries, including us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against Williams and its wholly-owned subsidiaries, including us. The matter is on appeal to the Tenth Circuit Court of Appeals.
Environmental Matters
We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that it is in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.
Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB), contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) in the late 1980s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous mercury clean-ups in Washington. Currently, we are conducting assessment and remediation activities needed to bring the sites up to Washington’s current environmental standards. At December 31, 2008, we had accrued liabilities totaling approximately $9.2 million for these costs which are expected to be incurred through 2014. The increase from prior year accruals is due to the completion of assessments at certain compressor station facilities. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. We consider these costs associated with compliance with environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard for ground-level ozone. Within three years, the EPA is expected to designate new eight-hour ozone non-attainment areas. Designation of new eight-hour ozone non-attainment areas will result in additional federal and state regulatory actions that will likely impact our operations. As a result, we expect the cost of additions to property, plant and equipment to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Safety Matters
Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (DOT PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $120 million and $145 million over the remaining assessment period of 2009 through 2012. The cost estimates have been revised to reflect refinements in the scope of required remediation and for increases in assessment and remediation costs. Our management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
Other Matters
In addition to the foregoing, various other proceedings are pending against us incidental to our operations.
Summary
Litigation, arbitration, regulatory matters, environmental matters, and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect on our future financial position.
Other Commitments
We have commitments for construction and acquisition of property, plant and equipment of approximately $12.4 million at December 31, 2008.
Cash Distributions to Partners
On or before the end of the calendar month following each quarter, beginning after the end of the first quarter 2008, available cash is distributed to our partners as required by our general partnership agreement. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves as established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.
In January 2008, we received net proceeds of $300.9 million from Williams Pipeline Partners L.P. for its purchase of a partnership interest and we made a distribution of $300.9 million to Williams. During the year ended December 31, 2008, we declared and paid equity distributions of $118.4 million to our partners, including $8.8 million to Williams representing available cash prior to Williams Pipeline Partners L.P.’s acquisition of its interest in us. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. In January 2009, we declared and paid equity distributions of $32.0 million to our partners.
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. DEBT, FINANCING ARRANGEMENTS AND LEASES
Debt Covenants
Our debt indentures contain restrictions on our ability to incur secured debt beyond certain levels.
Long-Term Debt
On April 5, 2007, we issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017 to certain institutional investors in a private debt placement. In August 2007, we completed the exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
On December 1, 2007, we retired $250 million of 6.625 percent senior unsecured notes due 2007 with $250 million borrowings under the Williams revolving credit agreement. The interest rate on our revolving credit borrowings was 5.68 percent at December 31, 2007.
On May 22, 2008, we issued $250.0 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. Interest is payable on June 15 and December 15 of each year, beginning December 15, 2008. We used these proceeds to repay our December 2007 $250.0 million loan under the Credit Facility. In September 2008, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.
In the second quarter 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 debt issuance, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate debt. The settlement resulted in a gain that is being amortized to reduce interest expense over the life of the related debt.
Long-term debt consists of the following:
As of December 31, 2008, cumulative sinking fund requirements and other maturities of long-term debt (at face value) for each of the next five years are as follows:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Line-of-Credit Arrangements
Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012 (Credit Facility). We have access to $400 million under the agreement to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $71 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2008. In December 2007, we borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250 million was repaid with proceeds from the issuance of $250 million of 6.05 percent senior unsecured notes due 2018. We did not access the agreement in 2008.
Lehman Commercial Paper Inc., which was committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction.
Significant financial covenants under the credit agreement include the following:
Leases
Our leasing arrangements include mostly premise and equipment leases that are classified as operating leases.
The major operating lease is a leveraged lease for our headquarters building, which became effective during 1982. The agreement has an initial term of approximately 27 years, with options for consecutive renewal terms of approximately 9 years and 10 years. As required by the terms of the lease, we have exercised our option to renew the term of the lease for approximately 9 years, beginning October 1, 2009. The major component of the lease payment is set through the initial and first renewal terms of the lease. Various purchase options exist under the building lease, including options involving adverse regulatory developments.
We sublease portions of our headquarters building to third parties under agreements with varying terms. Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Operating lease rental expense, net of sublease revenues, amounted to $4.9 million, $4.9 million, and ($1.2) million for 2008, 2007 and 2006, respectively. (See Note 1 - Reclassifications and Adjustments.)
On December 31, 2007, in connection with the sale of Parachute to an affiliate of Williams, Parachute leased the facilities back to us. We continue to operate the facilities under the FERC certificate. When Williams Field Services completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate. Under the terms of the lease, we pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral. This operating lease is not included in the future minimum annual rental payments shown above due to the contingent nature of the Parachute lease payments.
5. EMPLOYEE BENEFIT PLANS
Pension plans
We participate in Williams’ sponsored noncontributory defined benefit pension plans along with Williams and its subsidiaries that provide pension benefits for eligible participant employees. Cash contributions related to our participation in the plans totaled $7.7 million in 2008, $3.1 million in 2007 and $3.3 million in 2006. We expensed $3.5 million in 2008, $4.0 million in 2007 and $3.5 million in 2006. For the tax-qualified pension plans, we had historically recorded a regulatory asset or liability for the difference between pension expense as estimated under SFAS No. 87 and the amount we funded as a contribution to the pension plans. In the second quarter of 2007, we recorded $16.6 million in income for a change in accounting estimate related to this pension regulatory liability. As a result of additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.
Accumulated other comprehensive loss at December 31, 2008 and 2007, includes the following:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net actuarial losses of $3,848 thousand and prior services costs of $82 thousand related to the pension plans that are included in accumulated other comprehensive loss at December 31, 2008, are expected to be amortized in net periodic benefit expense in 2009.
Postretirement benefits other than pensions
We participate in a Williams sponsored plan along with Williams and its subsidiaries that provides certain retiree health care and life insurance benefits for our eligible participants that were hired prior to January 1, 1992. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $0.1 million in 2008 and 2007 and $2.4 million in 2006. We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to a regulatory asset or liability and any unrecovered amounts will be collected through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2008 and 2007 are $2.9 million and $17.8 million, respectively. No expense was recorded in 2008 or 2007. We expensed $2.3 million in 2006.
At December 31, 2008, regulatory liabilities include prior service credits of $2.8 million and net actuarial losses of $14.6 million related to other postretirement benefit plans. These amounts have not yet been recognized in net periodic benefit expense. At December 31, 2007, regulatory liabilities included prior service costs of $2.6 million and net actuarial gains of $6.4 million related to other postretirement benefit plans.
Defined contribution plan
Employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $2.1 million in 2008, $2.0 million in 2007 and $1.8 million in 2006.
Stock-Based Compensation
Plan Information
The Williams Companies, Inc. 2007 Incentive Plan (the “Plan”) was approved by stockholders on May 17, 2007. The Plan provides for Williams common-stock-based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees based on the fair value of such awards. We are also billed for our proportionate share of both Williams Gas Pipeline Company, LLC’s (WGP) and Williams’ stock-based compensation expense through various allocation processes.
Accounting for Stock-Based Compensation
Compensation cost for share-based payments is based on the grant date fair value. Total stock-
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
based compensation expense, included in administrative and general expenses, for the years ended December 31, 2008, 2007 and 2006 was $1.0 million, $1.1 million and $0.9 million, respectively, excluding amounts allocated from WGP and Williams.
6. INCOME TAXES
Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax.
The provision (benefit) for income taxes includes:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the statutory Federal income tax rate to the provision (benefit) for income taxes is as follows:
Prior to our conversion to a general partnership, we provided for income taxes using the asset and liability method as required by SFAS 109, “Accounting for Income Taxes,” through September 30, 2007. During 2006, as a result of additional analysis of our tax basis and book basis assets and liabilities, we recorded a $0.7 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet. Management concluded that the effect of this correction was not material to prior annual or interim periods, to 2006 results, or to the trend of earnings.
No cash payments for income taxes were made to or received from Williams in 2008. Net cash payments (received from) made to Williams for income taxes were $37.7 million and ($1.3) million in 2007 and 2006, respectively.
7. FINANCIAL INSTRUMENTS
Disclosures About the Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash, cash equivalents and advances to affiliate - The carrying amounts of these items approximates their fair value.
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-term debt - The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings. The carrying amount and estimated fair value of our long term debt, including current maturities, were $693.2 million and $572.0 million, respectively, at December 31, 2008, and $693.7 million and $710.9 million, respectively, at December 31, 2007.
8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES
Concentration of Off-Balance-Sheet and Other Credit Risk
During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:
Our major customers are located in the Pacific Northwest. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are regularly evaluated and historical collection losses have been minimal.
Related Party Transactions
As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2008 and 2007, the advances due to us by Williams totaled approximately $66.0 million and $39.1 million, respectively. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately zero percent at December 31, 2008. We received interest income from advances to Williams of $0.8 million, $3.0 million, and $3.9 million during 2008, 2007 and 2006, respectively. Such interest income is included in Other Income - net on the accompanying Statement of Income.
Williams’ corporate overhead expenses allocated to us were $16.9 million, $19.6 million and $18.7 million for 2008, 2007 and 2006, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $15.8 million, $16.6 million and $16.6 million for 2008, 2007 and 2006, respectively. These expenses are included in General and Administrative Expense on the accompanying Statement of Income.
During the periods presented, our revenues include transportation and exchange transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $14.8 million, $11.8 million and $3.4 million for 2008, 2007 and 2006, respectively. The increase from 2006 to 2007 is primarily due to capacity reservation revenues of $6.7 million related to the Parachute Lateral facility which was placed into service in May 2007.
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of January 1, 2008, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we pay monthly rent equal to the revenues collected from transportation services on the lateral less 3 percent to cover costs related to the operation of the lateral. This lease expense, totaling $10.1 million for the year ended December 31, 2008, is included in operation and maintenance expense on the accompanying consolidated statement of income.
We have entered into various other transactions with certain related parties, the amounts of which were not significant. These transactions and the above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.
9. ASSET RETIREMENT OBLIGATIONS
During 2008 and 2007, we adjusted the ARO liability and Property, Plant and Equipment for a change in the inflation and discount rates.
During 2008 and 2007, our overall asset retirement obligation changed as follows (in thousands):
The accrued obligations relate to our gas storage and transmission facilities. At the end of the useful life of our facilities, we are legally obligated to remove certain transmission facilities including underground pipelines, major river spans, compressor stations and meter station facilities. These obligations also include restoration of the property sites after removal of the facilities from above and below the ground.
10. REGULATORY ASSETS AND LIABILITIES
Our regulatory assets and liabilities result from our application of the provisions of SFAS No. 71 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and other. Regulatory liabilities are included in deferred credits and other noncurrent liabilities. These balances are presented on our balance sheet on a gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2008 and 2007:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. ACCUMULATED OTHER COMPREHENSIVE LOSS
Accumulated other comprehensive loss includes the following as of December 31, 2008 and 2007:
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. QUARTERLY INFORMATION (UNAUDITED)
The following is a summary of unaudited quarterly financial data for 2008 and 2007:
Second quarter 2007 results reflect an increase of $16.6 million in operating income and $10.3 million in net income due to the reversal of a pension regulatory liability, and an increase in net income of $3.8 million due to the recognition of deferred income related to the termination of the Grays Harbor transportation agreement. Third quarter 2007 net income includes a net increase of $9.0 million due to additional income related to the termination of the Grays Harbor transportation agreement. Fourth quarter net income includes an increase of $311.8 million due to the reversal of deferred income taxes resulting from our conversion to a non-taxable general partnership. The first, second and third quarters of 2007 have been restated to reflect the inclusion of Williams’ purchase price allocation.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 9A(T).
Item 9A(T). CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Northwest have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
See report set forth above in Item 8, Financial Statements and Supplementary Data.
Changes in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
None.
PART III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Management Committee Member and Executive Officers
Our Amended and Restated General Partnership Agreement provides that we will be managed by the two general partners. Each partner has designated a representative to serve as a member of the management committee. Our executive officers are elected by the management committee and hold office until relieved of such office by action of the management committee.
The following table sets forth certain information with respect to our executive officers and members of the management committee.
Mr. Wright has served as a member of our management committee since October 1, 2007. He served as a director of Northwest Pipeline Corporation from January 3, 2005 to September 30, 2007. Since January 3, 2005, he has also served as Senior Vice President of Northwest. He has also held various management positions with Williams since November 21, 2002. Mr. Wright is also a director of Williams Pipeline GP LLC, the general partner of WMZ.
Mr. Chappel has served as a member of our management committee since October 1, 2007. Since 2002, Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams. Mr. Chappel is a director of Williams Pipeline GP LLC, the general partner of WMZ. Mr. Chappel is also the director of Williams Partners GP LLC, the general partner of Williams Partners L.P.
Mr. Malcolm has served as our Chief Executive Officer since October 1, 2007. He served as a director of Northwest Pipeline Corporation from May 16, 2002 to September 30, 2007. Since May 16, 2002, Mr. Malcolm has served as President, Chief Executive Officer and Chairman of the Board of Williams. Mr. Malcolm is a director of Williams Pipeline GP LLC, the general partner of WMZ, a director of Williams Partners GP LLC, the general partner of Williams Partners L.P., and a director of Bank of Oklahoma, N.A. and the BOK Financial Corporation.
Mr. Rodekohr has served as our Vice President and Treasurer since October 1, 2007. Mr. Rodekohr served as Vice President and Treasurer of Northwest Pipeline Corporation from November 15, 2002 to September 30, 2007.
Ms. Bridges has served as our Vice President since October 1, 2007. Ms. Bridges served as a director of Northwest Pipeline Corporation from December 1, 2002 to September 30, 2007 and as a Vice President from August 14, 2000 to September 30, 2007.
Mr. Barnard has served as our Vice President since October 1, 2007. Mr. Barnard served as a director of Northwest Pipeline Corporation from April 1, 2002 to September 30, 2007 and Vice President from April 1, 2003 to September 30, 2007.
Mr. Hjalmarson has served as our Vice President since October 1, 2007. Mr. Hjalmarson served as Vice President of Northwest Pipeline Corporation from April 30, 2007 to September 30, 2007 and has held various management positions with Williams since 1982.
Mr. Conklin has served as our Vice President since October 1, 2007. Mr. Conklin served as Vice President and General Counsel of Northwest Pipeline Corporation from April 1, 2003 to September 30, 2007 and as Senior Vice President and General Counsel from April 1, 2002 to March 31, 2003.
Mr. Ferazzi has served as our Vice President since October 1, 2007. Mr. Ferazzi served as a Vice President of Northwest Pipeline Corporation from April 1, 2002 until September 30, 2007.
Section 16(a) Beneficial Ownership Reporting Compliance
We do not have publicly traded equity securities. Therefore, compliance with Section 16(a) of the Securities Exchange Act of 1934 is not required.
Code of Ethics
As an indirect subsidiary of Williams, we have not adopted a separate Code of Ethics. We follow the Code of Business Conduct adopted by Williams. The Code of Business Conduct adopted by Williams is located on Williams’ website at http://Corporate Responsibility - Corporate Governance - Ethics and Compliance Program - Williams’ Code of Business Conduct.
Corporate Governance
We do not have a separate Audit Committee, Nominating and Governance Committee, or Compensation Committee from Williams.
Item 11.
Item 11. EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
We are managed by the employees of Williams and each of our executive officers are employees of Williams. Each of our executive officers is compensated directly by Williams rather than by us. All decisions as to the compensation of our executive officers are made by Williams. Therefore, we do not have any policies or programs relating to compensation of our executive officers and do not make any decisions relating to such compensation. A full discussion of the policies and programs of Williams will be set forth in the proxy statement for Williams’ 2009 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors - SEC Filings.” Williams charges us an allocated amount for the services of Williams’ employees who dedicate time to our affairs.
Executive Compensation
The summary compensation table includes amounts allocated to Northwest by Williams for services provided by our executive officers.
2008 Summary Compensation Table
Compensation Committee Interlocks and Insider Participation
We do not maintain a separate compensation committee from Williams. Our executive officers during 2008 were employees of Williams and compensation decisions with respect to those individuals were determined by Williams.
Compensation of Directors
The members of the management committee are employees of Williams and receive no compensation for service on Northwest’s management committee.
Compensation Committee Report
We do not have a separate compensation committee from Williams. The management committee has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
Management Committee:
Donald R. Chappel
Phillip D. Wright
Item 12.
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
We do not have publicly traded equity securities; therefore, we do not have securities authorized for issuance under an equity compensation plan or securities owned by certain beneficial owners and management.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Our two general partners are subsidiaries of Williams. WGPC Holdings LLC owns 65 percent of our general partnership interest and WMZ owns the remaining 35 percent of our general partnership interest.
Although management of Northwest is vested in its partners, the partners of Northwest have agreed to delegate management of Northwest to a management committee. Decisions or actions taken by the management committee of Northwest bind Northwest. The management committee is composed of two representatives, with one representative being designated by Williams and one representative being designated by WMZ Each representative has full authority to act on behalf of the partner that designated such representative with respect to matters pertaining to that partnership. Each representative is an agent of the partner that designated that person and does not owe any duty (fiduciary or otherwise) to Northwest, any other partner or any other representative.
The management committee of Northwest meets no less often than quarterly, with the time and location of, and the agenda for, such meetings to be as the management committee determines. Special meetings of the management committee may be called at such times as a partner or management committee representative determines to be appropriate. Each member of the management committee is entitled to a vote equal to the percentage interest in Northwest of the respective partner represented. Except as noted below, the vote of a majority of the percentage interests represented at a meeting properly called and held constitutes the action of the management committee. Any action of the management committee may be taken by unanimous written consent.
The following actions require the unanimous approval of the management committee:
•
the liquidation, dissolution or winding up of Northwest or making any bankruptcy filing;
•
the issuance, incurrence, assumption or guarantee of any indebtedness or the pledge of any of Northwest’s assets;
•
filing or resolving a Section 4 general rate case proceeding under the Natural Gas Act or any other proceeding or controversy at FERC or an appeal of a FERC order, the outcome of which would cause (A) Northwest to have reduced revenue of, or pay penalties, refunds or interest in excess of, $50 million, or (B) Northwest to agree to any criminal penalty;
•
any amendment of the Northwest partnership agreement;
•
any distributions to Northwest’s partners, other than the distributions of available cash to be made at least quarterly as described below;
•
the admission of any person as a partner (other than a permitted transferee of a partner) or the issuance of any partnership interests or other equity interests of Northwest or any withdrawal by any partner from Northwest;
•
the transfer, redemption, repurchase or other acquisition of interests in Northwest;
•
the disposition of substantially all of the assets of Northwest or any portion of such assets with a value exceeding $20 million;
•
any merger or consolidation of Northwest with another person or any conversion or reorganization of Northwest;
•
entering into any activity or business that may generate income that may not be “qualifying income” under Section 7704 of the Internal Revenue Code;
•
the approval of Northwest’s budget;
•
the approval of a transfer by a partner of its interest in Northwest; and
•
any amendment to the administrative services agreement to which Northwest is a party.
Quarterly Cash Distributions
Under the Northwest general partnership agreement, on or before the end of the calendar month following each quarter, beginning after the end of the first quarter 2008, the management committee of Northwest is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of Northwest’s business and to comply with any applicable law or agreement.
Capital Calls to the Partners
Except as described below with regard to the Colorado Hub Connection Project, the Northwest general partnership agreement allows the management committee to require the partners to make additional capital contributions in accordance with their percentage interests. The management committee may issue capital calls to fund working and maintenance capital expenditures, as well as to fund expansion capital expenditures.
Restrictions on Transfer of Interests in Northwest
Each of the partners is allowed to transfer its general partnership interest in Northwest to an affiliate that is a wholly owned subsidiary of Williams or us, respectively. Otherwise, each Northwest partner has a “right of first offer” that requires a partner to offer the general partnership interest to the other partner prior to selling the interest to a third party. If the partner declines the right of first offer, the partner wishing to sell its interest has 120 days to sell the interest to a third party, provided that the sale is for at least equal value as offered to the other partner and other terms are not materially more favorable to the third party than the terms offered to the other partner.
Profit and Loss Allocations
In general, all items of income, gain, loss and deduction will be allocated to the partners in accordance with their percentage interests.
Agreement with Regard to Colorado Hub Connection Project
The Northwest general partnership agreement provides that the capital expenditures related to the Colorado Hub Connection Project will be funded by the affiliate of Williams holding the 65 percent general partnership interest in Northwest not owned by Williams Pipeline Partners L.P.
Williams’ Cash Management Program
We will invest cash through participation in Williams’ cash management program. The advances will be represented by one or more demand obligations. As a participant in Williams’ cash management program, Northwest makes advances to and receives advances from Williams. At December 31, 2008, the advances due to Northwest by Williams totaled approximately $66.0 million. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately zero percent at December 31, 2008. Northwest received interest income from advances to Williams of $0.8 million, $3.0 million and $3.9 million during 2008, 2007 and 2006, respectively.
Other Related Party Transactions
Williams’ corporate overhead expenses allocated to Northwest were $16.9 million, $19.6 million and $18.7 million for 2008, 2007 and 2006, respectively. Such expenses have been allocated to
Northwest by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to Northwest on a direct charge basis, which totaled $15.8 million, $16.6 million and $16.6 million for 2008, 2007 and 2006, respectively.
Northwest also has transportation and exchange transactions and agreements relating to the rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $14.8 million, $11.8 million and $3.4 million for 2008, 2007 and 2006, respectively.
As of January 1, 2008, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we pay monthly rent equal to the revenues collected from transportation services on the lateral less 3 percent to cover costs related to the operation of the lateral. This lease expense, totaling $10.1 million for the year ended December 31, 2008, is included in operation and maintenance expense on the accompanying consolidated statement of income.
Northwest has also entered into an administrative services agreement with Northwest Pipeline Services LLC, a wholly-owned subsidiary of Williams, to provide services that Northwest determines may be reasonable and necessary to operate its business, including employees, accounting, information technology, company development, operations, administration, insurance, risk management, tax, audit, finance, land, marketing, legal, and engineering, which services may be expanded, modified or reduced from time to time as agreed upon by the parties. Northwest Pipeline Services LLC is a variable interest entity for which Northwest is the primary beneficiary, and accordingly, is consolidated in the financial statements of Northwest.
The above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.
Item 14.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees for professional services provided by our independent auditors in each of the last two fiscal years in each of the following categories are:
Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultations.
As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The Williams audit committee policies and procedures for pre-approving audit and non-audit services will be set forth in the Proxy Statement for Williams’ 2009 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://williams.com under the heading “Investors - SEC Filings.”
PART IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1. Financial Statements
Index
(a) 2. Financial Statement Schedules
NORTHWEST PIPELINE GP
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
All other schedules have been omitted because they are not required to be filed.
(a) 3 and b. Exhibits:
(2)
Plan of acquisition, reorganization, arrangement, liquidation or succession:
(3)
Articles of incorporation and by-laws:
(4)
Instruments defining the rights of security holders, including indentures:
*
Exhibits so marked have heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and are incorporated herein by reference.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 26, 2009
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Date: February 26, 2009
EXHIBIT INDEX
Exhibit