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EX-12 - EX-12 - NORTHWEST PIPELINE LLC | c55980exv12.htm |
EX-24 - EX-24 - NORTHWEST PIPELINE LLC | c55980exv24.htm |
EX-23 - EX-23 - NORTHWEST PIPELINE LLC | c55980exv23.htm |
EX-32.A - EX-32.A - NORTHWEST PIPELINE LLC | c55980exv32wa.htm |
EX-31.B - EX-31.B - NORTHWEST PIPELINE LLC | c55980exv31wb.htm |
EX-31.A - EX-31.A - NORTHWEST PIPELINE LLC | c55980exv31wa.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
þ | Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2009
or
o | Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the transition period from _____________________ to _________________________
Commission File Number 1-7414
NORTHWEST PIPELINE GP
(Exact name of registrant as specified in its charter)
DELAWARE (State or other jurisdiction of incorporation or organization) |
26-1157701 (I.R.S. Employer Identification No.) |
|
295 Chipeta Way, Salt Lake City, Utah (Address of principal executive offices) |
84108 (Zip Code) |
(801) 583-8800
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
None
None
Securities registered pursuant to Section 12(g) of the Act:
None
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes
þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such files). Yes o
No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
(§229.405) is not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ (Do not check if a smaller Reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ
Documents Incorporated by Reference:
None
None
TABLE OF CONTENTS
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NORTHWEST PIPELINE GP
FORM 10-K
PART I
Item 1. | BUSINESS |
GENERAL
Northwest Pipeline GP (Northwest) owns and operates 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).
On December 31, 2009, Northwest was owned 35 percent by Williams Pipeline Partners Holdings
LLC, a wholly-owned subsidiary of Williams Pipeline Partners L.P. (WMZ) and 65 percent by WGPC
Holdings LLC, a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Through its
ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of
Northwest as of December 31, 2009.
On February 17, 2010, Williams completed a strategic restructuring,
pursuant to which Williams contributed its ownership in WGPC Holdings LLC to Williams Partners L.P. (WPZ), a publicly traded
Delaware limited partnership which is controlled by and consolidated with Williams. Through its ownership interests in each
of our partners, Williams indirectly owns 71.3 percent of Northwest as of February 17, 2010.
On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the
outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the
successful consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in Northwest
and Williams will hold an approximate 80 percent interest in WPZ.
In this report, Northwest is at times referred to in the first person as we, us or our.
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, 2009, we had long-term firm
transportation contracts, including peaking service, with aggregate capacity reservations of
approximately 3.7 Bcf* 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. |
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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 2009, we served a total of 129 transportation and storage customers. Our two largest
customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for
approximately 21.8 percent and 11.3 percent, respectively, of our total operating revenues for the
year ended December 31, 2009. 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 13.0 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.
| 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, 2009, our share of the firm seasonal storage service in this facility was approximately 7.7 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. |
| Plymouth LNG: We also own and operate a Liquefied 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. |
| 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. |
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.
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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 TransCanadas Gas Transmission Northwest (GTN) to
build the Palomar Gas Transmission project. This proposed project would consist of a greenfield
pipeline from GTNs system in central Oregon to Northwest Naturals system in western Oregon.
Palomar could also be used to transport natural gas from one of the proposed Columbia River LNG
terminals back to GTNs system.
We are also experiencing increased competition for domestic supply with the completion of
projects such as Kinder Morgans Rockies Express and Wyoming Interstates 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 Northwests 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, FERCs 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. However, recent U.S. and Canadian shale gas
discoveries and related technological advancements may impact future North American natural gas
flow patterns. 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), municipal utilities, direct industrial users, electric
utilities and independent 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. Northwests 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
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price differentials over time or between markets. Northwests 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 were completed during 2009 or are significant future
pipeline projects for which we have significant customer commitments.
Colorado Hub Connection Project
On November 10, 2009, we placed into service the new 27-mile, 24-inch diameter lateral
referred to as the Colorado Hub Connection Project (CHC Project). The new lateral connects the
Meeker/White River Hub near Meeker, Colorado to our mainline south of Rangely, Colorado, and is
estimated to cost up to $60 million.
The CHC Project combined the new lateral capacity with existing mainline capacity to provide
approximately 363 MDth per day of firm transportation from various receipt points to delivery
points on the mainline as far south as Ignacio, Colorado. Approximately 243 MDth per day of the
capacity was originally held by Pan-Alberta Gas under a contract that would have terminated on
October 31, 2012 and approximately 98 MDth per day was previously sold on a short-term basis.
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 in the Piceance Basin for our on-system and off-system markets. We
have entered into transportation agreements for approximately 363 MDth per day of capacity 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 April 2009, the FERC issued a certificate approving the CHC Project, including the
presumption of rolling in the costs of the project 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 million cubic feet per day share of the planned 2008
deliverability expansion and approximately 1.2 billion cubic feet of our share of the working
natural gas storage capacity expansion being 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 November 2009, we received approval from the FERC to construct 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 the existing compression at Vernal, which will enhance the efficiency of our system. We
executed a precedent agreement to provide 150 MDth per day of firm transportation service from the
Greasewood and Meeker Hubs in Colorado for delivery to the Opal Hub in Wyoming. We have proposed
to collect our maximum
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system rates, and have received approval from the FERC to roll-in the Sundance Trail Expansion
costs in any future rate cases.
OPERATING STATISTICS
Throughput
The following table summarizes volumes and capacity for the periods indicated:
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(In trillion British Thermal Units) | ||||||||||||
Total Throughput (1) |
769 | 781 | 757 | |||||||||
Average Daily Transportation Volumes |
2.1 | 2.1 | 2.1 | |||||||||
Average Daily Reserved Capacity Under Base Firm
Contracts, excluding peak capacity |
2.7 | 2.5 | 2.5 | |||||||||
Average Daily Reserved Capacity Under Short-Term
Firm Contracts (2) |
.5 | .7 | .8 |
(1) | Parachute Lateral volumes of 49 TBtu in 2009, 102 TBtu in 2008 and 55 TBtu in 2007 are excluded from total throughput as these volumes flowed 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, 2009.
Jan-Mar | Apr-Jun | Jul-Sep | Oct-Dec | Total | ||||||||||||||||
2009 | ||||||||||||||||||||
Revenues ($ in 000) |
$ | 111,548 | $ | 107,756 | $ | 106,615 | $ | 108,460 | $ | 434,379 | ||||||||||
Revenue % |
25.7 | % | 24.8 | % | 24.5 | % | 25.0 | % | 100 | % | ||||||||||
Operating Expenses ($ in 000) |
$ | 58,396 | $ | 60,743 | $ | 57,470 | $ | 57,261 | $ | 233,870 | ||||||||||
Throughput (TBtu) (1) |
224 | 173 | 166 | 206 | 769 | |||||||||||||||
Throughput % |
29.1 | % | 22.5 | % | 21.6 | % | 26.8 | % | 100 | % |
(1) | Parachute Lateral volumes are excluded from throughput as these volumes flowed 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:
| transportation and storage of natural gas; |
| rates and charges; |
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| terms of service including creditworthiness requirements; |
| construction of new facilities; |
| extension or abandonment of service and facilities; |
| accounts and records; |
| depreciation and amortization policies; |
| relationships with gas marketing functions within Williams; and |
| 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 FERCs 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
pipelines 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 pipelines FERC-approved tariff or established by
reference to FERCs regulations. Rate design and the allocation of costs also can impact a
pipelines 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 pipelines maximum recourse rates.
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 pipelines public utility assets.
Whether a pipelines owners have such actual or potential income tax liability will be reviewed by
FERC on a case-by-case basis.
In a 2007 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 pipelines earnings. In 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. The effect of the application of FERCs 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.
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.
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
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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 FERCs 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 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 (EPA) community right-to-know
regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and
comparable state statutes, require that information be maintained concerning hazardous materials
used or produced in 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
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otherwise relating to environmental protection. These laws and regulations may impose numerous
obligations that are applicable to our operations, including:
| requiring the acquisition of permits to conduct regulated activities; |
| restricting the manner in which we can release materials into the environment; |
| imposing investigatory and remedial obligations to mitigate pollution from former or current operations; |
| assessing administrative, civil, and criminal penalties for failure to comply with applicable legal requirements; and |
| 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 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.
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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
have established systems and procedures to meet our reporting
obligations under the Mandatory Reporting Rule related to greenhouse
gas emissions issued by the EPA in late 2009. Also, certain states in
which we have operations have established reporting obligations. We
have not incurred significant capital investment to meet the
obligations imposed by these new rules. The EPA is developing
additional regulations that will expand the scope of the Mandatory
Reporting Rule, with particular emphasis on natural gas operations.
We are participating directly and through trade associations in
developmental aspects of that prospective rulemaking. It is likely
that additional rules will be issued in 2010 which may expand our
reporting obligations as early as 2011. As those rules are still
being developed, at this time we are unable to estimate any capital
investment that may be required to comply.
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 Northwests natural gas pipeline is located in areas inhabited
by
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threatened or endangered species. If Northwests 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
Northwest has no employees. Services are provided to Northwest by Northwest Pipeline Services
LLC, a consolidated affiliate. As of January 31, 2010, Northwest Pipeline Services LLC had 440
employees.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with Williams and other Williams subsidiaries. Please see Item 8.
Financial Statements and Supplementary Data Notes to Consolidated Financial Statements: Note 1.
Summary of Significant Accounting Policies and Note 9. Transactions with Major Customers and
Affiliates and Part III, Item 13. Certain Relationships and Related Transactions, and Director
Independence.
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
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 forward-looking statements relate to anticipated financial
performance, managements plans and objectives for future operations, business prospects, outcome
of regulatory proceedings, market conditions and other matters. 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, seeks, could, may, should,
continues, estimates, expects, forecasts, intends, might, goals, objectives,
targets, planned, potential, projects, scheduled, will or other similar expressions.
These forward-looking statements are based on managements beliefs and assumptions and on
information currently available to management and include, among others, statements regarding:
| Amounts and nature of future capital expenditures; |
| Expansion and growth of our business and operations; |
| Financial condition and liquidity; |
| Business strategy; |
| Cash flow from operations or results of operations; |
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| Rate case filings; and |
| Natural gas 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 report. Many of the factors that will determine these results are beyond our ability to
control or predict. Specific factors that could cause actual results to differ from results
contemplated by the forward-looking statements include, among others, the following:
| Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital; |
| Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers); |
| The strength and financial resources of our competitors; |
| Development of alternative energy sources; |
| The impact of operational and development hazards; |
| Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation and rate proceedings; |
| Our costs for defined benefit pension plans and other postretirement benefit plans; |
| Changes in maintenance and construction costs; |
| Changes in the current geopolitical situation; |
| Our exposure to the credit risk of our customers; |
| 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; |
| Risks associated with future weather conditions; |
| Acts of terrorism; and |
| 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.
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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:
| fires, blowouts, cratering and explosions; | ||
| uncontrolled releases of natural gas; | ||
| pollution and other environmental risks; | ||
| natural disasters; | ||
| aging pipeline infrastructure and mechanical problems; | ||
| damages to pipelines and pipeline blockages; | ||
| operator error; | ||
| damage inadvertently caused by third party activity, such as operation of construction equipment; and | ||
| 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 pipelines 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.
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, WPZ and its other
affiliates, including Williams may
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not be 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. FERCs
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 Part I. Item 1. Business Pipeline System, Customers
and Competition 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 2010, 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:
| the level of existing and new competition to deliver natural gas to our markets; | ||
| the growth in demand for natural gas in our markets; | ||
| whether the market will continue to support long-term firm contracts; | ||
| whether our business strategy continues to be successful; | ||
| the level of competition for natural gas supplies in the production basins serving us; and | ||
| 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.
Competitive pressures could lead to decreases in the volume of natural gas contracted or
transported through our pipeline system.
Although most of our pipeline systems current capacity is fully contracted, the FERC has
taken certain actions to strengthen market forces in the natural gas pipeline industry that have
led to increased competition throughout the industry. In a number of key markets, interstate
pipelines are now facing competitive pressure from other major pipeline systems, enabling local
distribution companies and end users to choose a transmission provider based on considerations
other than location. Other entities could construct new pipelines or expand existing pipelines
that could potentially serve the same markets as our
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pipeline system. Any such new pipelines could offer transportation services that are more
desirable to shippers because of locations, facilities, or other factors. These new pipelines
could charge rates or provide service to locations that would result in greater net profit for
shippers and producers and thereby force us to lower the rates charged for service on our pipeline
in order to extend our existing transportation service agreements or to attract new customers. We
are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve
which, if the proposed projects proceed, could increase the competitive pressure upon us. There
can be no assurance that we will be able to compete successfully against current and future
competitors and any failure to do so could have a material adverse effect on our business and
results of operations.
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, including
environmental regulations, 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, if natural gas supplies are diverted to serve other markets, or if
environmental regulators restrict new natural gas drilling, 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.
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Some portions of our current pipeline infrastructure and other assets have been in use for many
decades, which may adversely affect our business.
Some portions of our assets, including our pipeline infrastructure, have been in use for many
decades. The current age and condition of our assets 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.
We are subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to climate change.
Climate change and the costs that may be associated with its impacts and the regulation of
greenhouse gases have the potential to affect our business in many ways, including negatively
impacting the costs we incur in providing our products and services, the demand for and consumption
of our products and services (due to change in both costs and weather patterns), and the economic
health of the regions in which we operate, all of which can create financial risks.
Our operations are subject to governmental laws and regulations relating to the protection of the
environment, including those relating to climate change, which may expose us to significant costs
and liabilities and could exceed our current expectations.
The risk of substantial environmental costs and liabilities is inherent in natural gas
transportation and storage operations, and we may incur substantial environmental costs and
liabilities in the performance of these types of operations. Our 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 Part I, Item 1.
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, the
imposition of stricter conditions on or revocation of permits, 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 our
business, some of which may be material due to our 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
CERCLA, RCRA and analogous state laws, and 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 arising from our operations. In addition, increasingly strict laws,
regulations and enforcement policies could materially increase our compliance costs and the cost of
any remediation that may become necessary. Our insurance may not cover all environmental risks and
costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control
requirements or liabilities resulting from non-compliance with required operating or other
regulatory permits. Also, we might not be able to obtain or maintain from time to time all
required environmental regulatory approvals for our operations. If there is a delay in obtaining
any required environmental
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regulatory approvals, or if we fail to obtain and comply with them, the operation of our facilities
could be prevented or become subject to additional costs resulting in potentially material adverse
consequences to our business, financial condition, results of operations and cash flows.
We make assumptions and develop expectations about possible expenditures related to
environmental conditions based on current laws and regulations and current interpretations of those
laws and regulations. If the interpretation of laws or regulations, or the laws and regulations
themselves, change, our assumptions may change, and any new capital costs incurred to comply with
such changes may not be recoverable under our regulatory rate structure or our customer contracts.
In addition, new environmental laws and regulations might adversely affect our activities,
including storage and transportation, as well as waste management and air emissions. For instance,
federal and state agencies could impose additional safety requirements, any of which 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.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to
as greenhouse gases (GHGs), may be contributing to warming of the earths atmosphere, and various
governmental bodies have considered legislative and regulatory responses in this area. Legislative
and regulatory responses related to GHGs and climate change create the potential for financial
risk. The United States Congress and certain states have for some time been considering various
forms of legislation related to GHG emissions. There have also been international efforts seeking
legally binding reductions in emissions of GHGs. In addition, increased public awareness and
concern may result in more state, federal, and international proposals to reduce or mitigate the
emission of GHGs.
Several bills have been introduced in the United States Congress that would compel GHG
emission reductions. On June 26, 2009, the U.S. House of Representatives passed the American
Clean Energy and Security Act which is intended to decrease annual GHG emissions through a variety
of measures, including a cap and trade system which limits the amount of GHGs that may be emitted
and incentives to reduce the nations dependence on traditional energy sources. The U.S. Senate is
currently considering similar legislation, and numerous states have also announced or adopted
programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final
determination that six GHGs are a threat to public safety and welfare. This determination could
ultimately lead to the direct regulation of GHG emissions in our industry under the Clean Air Act.
While it is not clear whether or when any federal or state climate change laws or regulations will
be passed, any of these actions could result in increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage
any GHG emissions program. If we are unable to recover or pass through a significant level of our
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 GHG emissions 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.
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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, 2009, our two largest customers were Puget Sound Energy, Inc. and Northwest
Natural Gas Company. These customers accounted for approximately 33.1 percent of our operating
revenues for the year ended December 31, 2009. 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, unless we are able to acquire comparable
revenues from other sources.
We are exposed to the credit risk of our customers, and our credit risk management may not be
adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by 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, our credit procedures and policies may not be
adequate to fully eliminate customer credit risk. We cannot predict to what extent our business
would be impacted by deteriorating conditions in the economy, including declines in our customers
creditworthiness. If we fail to adequately assess the creditworthiness of existing or future
customers, unanticipated deterioration in their creditworthiness and any resulting increase in
nonpayment and/or nonperformance by them could cause us 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
business, results of operations, cash flows 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 temporarily or permanently unavailable for any reason, or if throughput
were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating
pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or
facilities or other causes, we and our customers would have reduced capacity to transport, store or
deliver natural gas to end use markets, 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.
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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, its subsidiaries and certain of 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 onshore assets and resulting business
interruption caused by terrorist acts. 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 hurricane losses in recent years have impacted named windstorm insurance coverage, rates and
availability for Gulf of Mexico area exposures, 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:
| the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; | ||
| the availability of skilled labor, equipment, and materials to complete expansion projects; | ||
| 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; | ||
| impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; | ||
| 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 and Williams and WPZs public indentures contain financial and operating restrictions
that may limit our access to credit and affect our ability to operate our business. In addition,
our ability to obtain credit in the future will be affected by Williams and WPZs credit ratings.
Our public indentures contain
various covenants that, among other things, limit our ability to
grant certain liens to support indebtedness, merge, or sell substantially all of our assets. In
addition, our new credit facility entered into as part of Williams restructuring (New Credit Facility) contains certain financial covenants and restrictions on our
ability and our subsidiaries ability to incur indebtedness, to consolidate or allow any material
change in the nature of our business, enter into certain affiliate transactions, and make certain
distributions during an event of default. These covenants could adversely affect our ability to
finance our future operations or capital needs or engage in, expand or pursue our business
activities and prevent us from engaging in certain transactions that might otherwise be considered
beneficial to us. Our ability to comply with these covenants may be affected by events beyond our
control, including prevailing economic, financial and industry conditions. If market or other
economic conditions deteriorate, our current assumptions about future economic conditions turn out
to be incorrect or unexpected events occur, our ability to comply with these covenants may be
significantly impaired.
Williams and WPZs public indentures contain covenants that restrict their and our ability to incur
liens to support indebtedness. These covenants could adversely affect our ability to finance our
future operation or capital needs or engage in, expand or pursue our business activities and
prevent us from engaging in certain transactions that might otherwise be considered beneficial to
us. Williams and WPZs ability to comply with the covenants contained in their respective debt instruments may be
affected by events beyond our and their control, including prevailing economic, financial and
industry conditions. If market or other economic conditions deteriorate, Williams or WPZs ability to
comply with these covenants may be negatively impacted.
Our failure to comply with the covenants in our debt agreements 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. Certain payment defaults or an acceleration under
our public indentures or other material indebtedness could cause a cross-default or
cross-acceleration of our New Credit Facility. 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 our New Credit Facility
cross-defaults, 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. For more information regarding our debt agreements, please
read Managements Discussion and Analysis of Financial Condition and Results of
OperationsCapital Resources and Liquidity.
Substantially
all of Williams and WPZs operations are conducted through their respective subsidiaries. Williams
and WPZs cash flows are substantially derived from loans, dividends and distributions paid to them by
their respective
subsidiaries.
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Williams and WPZs cash flows are typically utilized to
service debt and pay dividends or distributions on their equity, with the balance, if any,
reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with
Williams and WPZ , our ability to obtain credit will be affected by Williams and WPZs credit ratings. If Williams or WPZ
were to experience deterioration in their respective credit standing or financial condition, our access to
credit and our ratings could be adversely affected. Any future downgrading of a Williams or WPZs credit
rating would likely also result in a downgrading of our credit rating. A downgrading of a
Williams or WPZs credit rating could limit our ability to obtain financing in the future upon favorable
terms, if at all.
Future disruptions in the global credit markets may make debt markets less accessible, create a
shortage in the availability of credit and lead to credit market volatility.
In 2008, global credit markets experienced a shortage in overall liquidity and a resulting
disruption in the availability of credit. Future disruptions in the global financial marketplace,
including the bankruptcy or restructuring of financial institutions, could make debt markets
inaccessible and adversely affect the availability of credit already arranged and the availability
and cost of credit in the future. We have availability under the New Credit Facility, but our
ability to borrow under that facility could be impaired if one or more of our lenders fails to
honor its contractual obligation to lend to us.
Adverse economic conditions could negatively affect our results of operations.
A slowdown in the economy has 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 credit ratings could impact our liquidity, access to capital and our costs of
doing business, and maintaining our 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:
| economic downturns; | ||
| deteriorating capital market conditions; | ||
| declining market prices for natural gas; | ||
| terrorist attacks or threatened attacks on our facilities or those of other energy companies; | ||
| 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. Credit ratings are not recommendations to buy, sell or hold investments in the
rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies
and 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.
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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.
As of December 31, 2009, our general partners were both indirectly controlled by Williams. As
of February 17, 2010, we are an indirect partially-owned subsidiary of WPZ, approximately 82
percent of whose limited partnership interests as of such date are owned by Williams. The majority
interest in our business is owned by a subsidiary of WPZ. As a result, WPZ exercises substantial
control over our business and operations and makes determinations with respect to, among other
things, the following:
| payment of distributions and repayment of advances; | ||
| decisions on financings and our capital raising activities; | ||
| mergers or other business combinations; and | ||
| acquisition or disposition of assets. |
Our majority partners board of directors could decide to increase distributions or advances
to our partners consistent with existing debt covenants. This could adversely affect our
liquidity.
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 rate of
return.
Our interstate natural gas transportation and storage operations are subject to federal, state
and local regulatory authorities. Specifically, our interstate pipeline transportation and storage
services and related assets are subject to regulation by FERC. The federal regulation extends to
such matters as:
| transportation of natural gas in interstate commerce; | ||
| rates, operating terms and conditions of service, including initiation and discontinuation of services; | ||
| the types of services we may offer to our customers; | ||
| certification and construction of new facilities; | ||
| acquisition, extension, disposition or abandonment of facilities; | ||
| accounts and records; | ||
| depreciation and amortization policies; | ||
| relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and | ||
| 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.
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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 FERCs 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
managements 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 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.
The outcome of future rate cases will determine the amount of income taxes that we will be allowed
to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in
its 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 pipelines public utility assets.
The extent to which owners of pipelines have such actual or potential income tax liability will be
reviewed by FERC on a case-by-case basis in rate cases where the amounts of the allowances will be
established.
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,
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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, 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 allocation from Williams for costs for its defined benefit pension plans and other
postretirement benefit plans are affected by factors beyond our and Williams control.
As we have no employees, employees of Williams and its affiliates provide services to us. As
a result, we are allocated a portion of Williams costs in defined benefit pensions plans covering
substantially all of Williams or its affiliates employees providing services to us, as well as a
portion of the costs of other postretirement benefit plans covering certain eligible participants providing
services to us. The timing and amount of our allocations under the defined benefit pension plans
depend upon a number of factors Williams controls, including changes to pension plan benefits, as
well as factors outside of Williams control, such as asset returns, interest rates and changes in
pension laws. Changes to these and other factors that can significantly increase our allocations
could have a significant adverse effect on our financial condition and 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 floods, earthquakes, landslides,
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 have been unable to
obtain insurance on commercially reasonable terms or insurance may not be available. A significant
disruption in operations
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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.
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. | UNRESOLVED STAFF COMMENTS |
None.
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. | 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 4. Contingent Liabilities
and Commitments Legal Proceedings.
Item 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
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PART II
Item 5. | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
On December 31, 2009, we were 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 as of December 31, 2009.
On February 17, 2010, Williams completed a strategic restructuring,
pursuant to which Williams contributed its ownership in WGPC Holdings LLC to WPZ,
a publicly traded Delaware limited
partnership which is controlled by and consolidated with Williams. Through its ownership interests in each of our partners,
Williams indirectly owns 71.3 percent of us as of February 17, 2010.
On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the
outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the
successful consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in us and
Williams will hold an approximate 80 percent interest in WPZ.
We paid $135.0 million and $419.3 million in cash distributions to our partners during 2009
and 2008, respectively.
Item 6. | SELECTED FINANCIAL DATA |
The following financial data should be read in conjunction with Part II, Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8.
Financial Statements and Supplementary Data.
Year Ended December 31, | ||||||||||||||||||||
2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
(Restated) (B) | (Restated) (B) | (Restated) (B) | (Restated) (B) | |||||||||||||||||
(Thousands of Dollars) | ||||||||||||||||||||
Income Statement Data: |
||||||||||||||||||||
Operating revenues |
$ | 434,379 | $ | 434,854 | $ | 421,851 | $ | 324,250 | $ | 321,457 | ||||||||||
Net income |
153,651 | 155,371 | 439,726 | (A) | 54,462 | 68,974 | ||||||||||||||
Balance Sheet Data (at
period end): |
||||||||||||||||||||
Total assets |
2,081,277 | 2,078,812 | 2,033,596 | 2,034,748 | 1,661,324 | |||||||||||||||
Long-term debt, including
current maturities |
693,437 | 693,240 | 693,736 | 687,075 | 520,080 | |||||||||||||||
Total owners equity |
1,207,150 | 1,210,547 | 1,177,098 | 846,809 | 728,505 | |||||||||||||||
Cash Distributions |
135,000 | 419,342 | 109,770 | | 50,000 |
Note: | Earnings and distributions/dividends per partnership unit/common share are not presented for 2005 through 2009. We were a wholly-owned subsidiary of Williams at December 31, 2007 and for all prior periods presented. Distributions for 2009 and 2008 were made to our partners based upon each partnerships ownership interest. |
(A) | 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. On October 1, 2007, we reversed deferred income tax liabilities of approximately $311.8 million to income and $0.2 million of deferred income tax assets to other comprehensive income. | |
(B) | Our financial statements have been restated as described in Item 8. Financial Statements and Supplementary DataNotes to Consolidated Financial StatementsNote 2. Restatement. Accordingly, our 2005, 2006, 2007, and 2008 selected financial data has been restated to reflect |
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the change in accounting treatment. The net impact of the balance sheet corrections resulted in an adjustment to loans to affiliate which have been reclassified to equity. A reconciliation between our original basis in our total assets and liabilities and the selected financial data above follows: |
Year Ended December 31, | ||||||||||||||||
2008 | 2007 | 2006 | 2005 | |||||||||||||
(Thousands of Dollars) | ||||||||||||||||
Consolidated Balance Sheets: |
||||||||||||||||
Total assets, as previously reported |
$ | 2,082,172 | $ | 2,056,471 | $ | 2,049,324 | $ | 1,692,371 | ||||||||
Benefit plans correction |
3,360 | 22,875 | 14,576 | 31,047 | ||||||||||||
Total assets, as restated |
$ | 2,078,812 | $ | 2,033,596 | $ | 2,034,748 | $ | 1,661,324 | ||||||||
Total owners equity, as previously
reported , |
$ | 1,184,714 | $ | 1,185,616 | $ | 857,945 | $ | 756,346 | ||||||||
Net (increase) decrease of benefit
plans correction |
(25,833 | ) | 8,518 | 11,136 | 27,841 | |||||||||||
Total owners equity, as restated |
$ | 1,210,547 | $ | 1,177,098 | $ | 846,809 | $ | 728,505 | ||||||||
Item 7. | MANAGEMENTS 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.
On January 20, 2010, we concluded that our financial statements for the year ended December
31, 2008 should be restated due to the manner in which we have presented and recognized pension and
postretirement obligations in certain benefit plans for which Williams is the plan sponsor. We
have previously recorded allocated amounts related to these plans on a single-employer basis rather
than a multi-employer accounting model. As the plan assets are not legally segregated and we are
not contractually required to assume these obligations upon withdrawal, we have now concluded that
the appropriate accounting model for these historical financial statements is a multi-employer
model. The restatement did not have an impact on our 2008 or 2007 Net Income as our expense
recognized approximated our contributions to the Williams-sponsored plans, nor did it have any
impact on our 2008 or 2007 Statement of Cash Flows.
For a discussion of additional information on the restatement, see Item 8. Financial
Statements and Supplementary Data Notes to Consolidated Financial Statements Note 2.
Restatement.
RECENT DEVELOPMENTS
On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed its ownership in WGPC Holdings LLC to WPZ, a publicly traded Delaware limited
partnership which is controlled by and consolidated with Williams. Through its ownership interests in each of our partners,
Williams indirectly owns 71.3 percent of us as of February 17, 2010.
On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the
outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the successful
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consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in us and Williams will
hold an approximate 80 percent interest in WPZ.
HOW WE EVALUATE OUR OPERATIONS
We evaluate our business on the basis of a few key measures:
| the level of capacity reserved under our long-term firm transportation and storage contracts; | ||
| the level of revenues provided by our short-term firm and interruptible transportation and storage services; | ||
| our operating expenses; and | ||
| 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, 2009, approximately 4.4 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
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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 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 agreements.
In accordance with Williams restructuring of its business, our participation in the Williams
cash management program was terminated. In February 2010, our management committee authorized
a cash distribution which included the amount of our outstanding advances as of January 31, 2010.
Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our
Owners Equity as the advances will not be available to us as working capital. As a result of the
restructuring, we will become a participant in the WPZ cash management program.
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.
Please 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, 2009, we had long-term firm transportation
contracts, including peaking service, with aggregate capacity reservations of approximately 3.7 Bcf
of natural gas per day. We also have approximately 13.0 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
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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.
OUTLOOK
The overall economic recession and challenging financial markets during the past year have
impacted our business. In the current economic environment, many financial markets, institutions
and other businesses remain under considerable stress. These events continue to impact our
business. However, we note the following:
| We have no significant debt maturities until 2016. | ||
| As of December 31, 2009, we have approximately $66.8 million of available cash from return of advances made to affiliates and available capacity under our Credit Facility. (See further discussion in Managements Discussion and Analysis of Financial Condition and Results of Operations Method of Financing.) | ||
| 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. |
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. Please see Part 1, Item 1. Business
Capital Projects.
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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 managements judgment.
Regulatory Accounting
We are regulated by the FERC. The Accounting Standards Codification Topic 980, Regulated Operations
(Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and
liabilities
consistent with the economic effect of the way in which regulators establish rates if the rates established
are designed to recover the costs of providing the regulated service and if the competitive
environment makes it probable that such rates can be charged and collected. Accounting for businesses that
are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated
businesses. Transactions that are recorded differently as a result of regulatory accounting requirements
include the
capitalization of an equity return component on regulated capital projects, capitalization of other project costs,
retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset
retirement obligations
and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that
it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements
include the effects of the types of transactions described above that result from regulatory accounting requirements. Management uses
judgment in determining the probability that regulatory assets will be recoverable from, or regulatory
liabilities will be refunded to, customers. A summary of regulatory assets and liabilities is included in Note 11 of Notes to
Consolidated Financial Statements.
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 managements 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 managements 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.
RESULTS OF OPERATIONS
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 2009, 2008 and 2007.
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, 2008 and 2009
Operating revenues decreased $0.5 million, or less than one percent, for the year ended
December 31, 2009 as compared to the year ended December 31, 2008. This decrease is primarily
attributed to $4.4 million lower revenues due to the termination of the Parachute Lateral lease
agreement on August 1, 2009, and was mostly offset by higher transportation revenues of $1.7
million resulting primarily from an increase in firm transportation under long-term contracts and
higher storage revenues of $2.6 million resulting primarily from incremental reservation charges
associated with the Jackson Prairie deliverability expansion that was placed in service on November
1, 2008. The decrease in the Parachute Lateral lease revenues is substantially offset by a
decrease in lease expense described below.
Our transportation service accounted for 96 percent of our operating revenues for each of the
years ended December 31, 2009 and 2008. Additionally, gas storage service accounted for 4 percent
and 3 percent of operating revenues for the years ended December 31, 2009 and 2008, respectively.
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Operating expenses increased $0.2 million, or less than one percent. This increase is due
primarily to i) higher pension expense of $4.0 million, ii) higher allocated overhead from Williams
of $3.0 million attributed primarily to higher pension expense, and iii) higher labor of $1.6
million attributed primarily to pipeline maintenance. These increases were mostly offset by i)
lower taxes, other than income taxes, of $2.7 million primarily attributed to lower than
anticipated property tax settlements and lower sales and use taxes resulting from lower fuel usage
and a refund of taxes from prior years, ii) lower lease expense of $1.3 million attributed to the restructuring of the Salt Lake City headquarters building lease, and iii) $4.3
million lower expense from the termination of the Parachute Lateral lease agreement.
Other income net increased $0.3 million, or 20 percent, due primarily to higher allowance
for equity funds used during construction of $1.2 million attributed to higher capital expenditures
in 2009, partially offset by lower interest income from affiliates of $0.7 million attributed to
lower interest rates on advances to affiliates.
Interest charges increased $1.4 million, or 3 percent, due primarily to 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.
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
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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.
CAPITAL RESOURCES AND LIQUIDITY
Our ability to finance operations (including the funding of capital expenditures and
acquisitions), to meet our debt obligations and to refinance indebtedness depends on our ability to
generate future cash flows 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 decisions on
the rates we are able to establish for our transportation and storage services.
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 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 agreements. During 2009, we distributed $135.0 million of available cash to our partners.
In accordance with Williams restructuring of its business, our participation in the Williams
cash management program was terminated. In February 2010, our management committee authorized
a cash distribution which included the amount of our outstanding advances as of January 31, 2010.
Accordingly, the balance outstanding at December 31, 2009 was reflected as a reduction of our
Owners Equity as the advances will not be available to us as working capital. Effective with the
restructuring, we will become a participant in the WPZ cash management program.
We fund our capital spending requirements with cash from operating activities, third party
debt and contributions from our partners with the exception of the CHC Project, which was funded by
capital contributions from Williams. Through December 31, 2009, we have received $50.8 million in
capital contributions from Williams to fund the CHC Project.
SOURCES (USES) OF CASH
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Thousands of Dollars) | ||||||||||||
Net cash provided (used) by: |
||||||||||||
Operating activities |
$ | 234,798 | $ | 239,014 | $ | 205,357 | ||||||
Financing activities |
(83,608 | ) | (126,848 | ) | (142,523 | ) | ||||||
Investing activities |
(151,133 | ) | (112,318 | ) | (63,826 | ) | ||||||
Increase (decrease) in cash
and cash equivalents |
$ | 57 | $ | (152 | ) | $ | (992 | ) | ||||
Operating Activities
Our net cash provided by operating activities in 2009 decreased $4.2 million from 2008. This
decrease is primarily attributed to changes in other noncurrent assets and liabilities and working
capital, partially offset by an increase in our cash operating results.
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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.
Financing Activities
2009
| We paid distributions of $135.0 million to our partners. | ||
| We received $49.2 million in capital contributions from Williams for the CHC Project. |
2008
| We issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018. | ||
| We repaid the $250 million borrowed under the Williams revolving credit agreement in 2007. | ||
| We received proceeds of $300.9 million from the sale of partnership interest. | ||
| We paid distributions of $419.3 million to our partners. |
2007
| We issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017. | ||
| We borrowed $250 million under the Williams revolving credit agreement. | ||
| We retired $175 million of 8.125 percent senior unsecured notes due 2010. | ||
| We retired $250 million of 6.625 percent senior unsecured notes due 2007. | ||
| We paid distributions of $109.8 million to Williams. |
Investing Activities
2009
| Capital expenditures totaled $152.6 million, primarily related to normal maintenance and compliance projects and the CHC Project. |
2008
| Capital expenditures totaled $88.5 million, primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility. | ||
| We advanced $26.9 million to Williams. |
2007
| Capital expenditures totaled $156.8 million, primarily related to normal maintenance and compliance. | ||
| We received $79.8 million of proceeds from the sale of the Parachute Lateral to an affiliate. | ||
| We received $10.9 million repayment of advances made to Williams. |
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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 2009, we made distributions of available cash of $135.0 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,
2009 and 2008, the advances due to us by Williams totaled approximately $66.8 million and $66.0
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 0.05 percent and zero
percent at December 31, 2009 and 2008, respectively.
In accordance with Williams restructuring of its business, our participation in the Williams
cash management program was terminated. In February 2010, our management committee authorized
a cash distribution which included the amount of our outstanding advances as of January 31, 2010.
Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our
Owners Equity as the advances will not be available to us as working capital. As a result of the
restructuring, we will become a participant in the WPZ cash management program.
Credit Agreement
Williams has an unsecured, $1.5 billion credit facility with a maturity date of May 1, 2012
(Credit Facility). Prior to Williams restructuring, we had access to $400 million under the Credit Facility to the extent not
otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit
Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we
expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million.
Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lenders
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) based on the unused portion of the Credit Facility. The margins and commitment fee
are generally based on the specific borrowers senior unsecured long-term debt ratings. As of
December 31, 2009, there were no letters of credit issued by the participating institutions and no
revolving credit loans outstanding. In December 2007, we borrowed $250.0 million under the
Credit Facility 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 Credit Facility in 2008 or 2009. Please 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
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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 Facility 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
borrowers indebtedness and may terminate lending to all borrowers under the Credit Facility.
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 Facility would
terminate and all indebtedness outstanding under the Credit Facility would be accelerated.
On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed
substantially all of its domestic midstream and pipeline businesses, which includes
us, into WPZ. We are now a partially-owned subsidiary of WPZ.
As part of the restructuring, we were removed as borrowers under the Credit Facility, and on
February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit
facility (New Credit Facility) with WPZ and Transcontinental Gas Pipe Line Company, LLC (Transco),
as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named
therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by
up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility
to the extent not otherwise utilized by WPZ and Transco. At closing, WPZ borrowed $250 million
under the New Credit Facility to repay the term loan outstanding under its existing senior
unsecured credit agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to,
at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.s adjusted base
rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable
margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent,
(ii) Citibank N.A.s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ
pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit
Facility. The applicable margin and the commitment fee are determined by reference to a pricing
schedule based on a borrowers senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a
borrowers and its respective subsidiaries ability to incur indebtedness, grant certain liens
supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter
into certain affiliate transactions, make certain distributions during an event of default, and
allow any material change in the nature of its business.
Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before
Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit
Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and
our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt)
is not permitted to be greater than 55 percent. Each of the above ratios will be tested, beginning
June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a
rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default
relating to non-payment of principal, interest or fees, inaccuracy of representations and
warranties in any material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied
judgments and a change of control. If an event of default with respect to a borrower occurs under
the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers
and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility
and exercise other rights and remedies.
Long-Term Financing
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 future amounts raised, if any, in the capital markets. We anticipate that we
will be able to access
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public and private debt markets on terms commensurate with our credit
ratings to finance our capital requirements, when needed.
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, increase transmission or storage capacities
from existing levels or enhance revenues. We anticipate 2010 capital expenditures will be between
$120 million and $140 million. Of this total, $95 million to $115 million is considered
nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2010, we expect to
fund our capital expenditures with cash from operations, with the exception of the final costs for
the CHC Project which will be funded by capital contributions from Williams.
Property, plant and equipment additions were $156.6 million, $78.6 million and $157.2 million
for 2009, 2008 and 2007, respectively. The $78.0 million increase from 2008 to 2009 is primarily
attributed to expenditures related to pipeline integrity, the CHC Project, and the Sundance Trail
Expansion Project.
CREDIT RATINGS
During 2009, the credit ratings on our senior unsecured long-term debt remained unchanged with
investment grade ratings from all three agencies, as shown below.
Moodys Investors Service
|
Baa2 | |
Standard and Poors
|
BBB- | |
Fitch Ratings
|
BBB |
At December 31, 2009 and through the date of this report, the evaluation of our credit rating
is stable from Moodys Investors Service and Fitch Ratings. On January 12, 2010, Standard and
Poors revised our ratings outlook to positive from stable.
With respect to Moodys, 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 indicates a ranking at the lower end of the category.
With respect to Standard and Poors, 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 Poors 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 Poors may modify its
ratings with a + or a - sign to show the obligors 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 obligors relative standing
within a major rating category.
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OTHER
Contractual Obligations
The table below summarizes the maturity dates of our more significant contractual obligations
and commitments as of December 31, 2009 (in millions of dollars).
2010 | 2011-2012 | 2013-2014 | Thereafter | Total | ||||||||||||||||
Long-term debt,
including current
portion: |
||||||||||||||||||||
Principal |
$ | | $ | | $ | | $ | 695.0 | $ | 695.0 | ||||||||||
Interest |
44.4 | 88.9 | 88.9 | 165.5 | 387.7 | |||||||||||||||
Operating leases |
2.3 | 4.6 | 4.5 | 11.8 | 23.2 | |||||||||||||||
Purchase Obligations: |
||||||||||||||||||||
Natural gas
purchase,
storage,
transportation and
construction |
27.1 | 4.6 | 4.1 | | 35.8 | |||||||||||||||
Other |
0.1 | 0.3 | 0.3 | 6.7 | 7.4 | |||||||||||||||
Other long-term
liabilities,
including current
portion (1)(2) |
1.5 | 3.0 | 3.3 | | 7.8 | |||||||||||||||
Total |
$ | 75.4 | $ | 101.4 | $ | 101.1 | $ | 879.0 | $ | 1,156.9 | ||||||||||
(1) | Does not include estimated settlement of asset retirement obligations. (Please see Item 8 Financial Statements and Supplementary Data Notes to Consolidated Financial Statements: Note 10. Asset Retirement Obligations.) | |
(2) | Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. (Please see Item 8. Financial Statements and Supplementary Data Notes to Consolidated Financial Statements: Note 11. 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 may limit our ability to price services or products to ensure
recovery of inflations effect on costs.
Environmental Matters
As discussed in Item 8. Financial Statements and Supplementary Data Notes to Consolidated
Financial Statements: Note 4. 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
37
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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 4. 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 liquidity or financial condition. Please see Item 8. Financial Statements and
Supplementary Data Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities
and Commitments.
Regulatory Proceedings
Please see Item 8. Financial Statements and Supplementary Data Notes to Consolidated
Financial Statements: Note 3. Rate and Regulatory Matters and Note 4. 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/or borrowings under the New Credit Facility, will provide us with sufficient
liquidity to meet our capital requirements. We anticipate that we will be able to access public and
private debt markets on terms commensurate with our credit ratings to finance our capital
requirements, when needed.
Item 7A. | QUANTITATIVE AND QUALITATIVE 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):
December 31, 2009 | ||||
Fixed rates on long-term debt: |
||||
5.95% senior unsecured notes due 2017 |
$ | 185,000 | ||
6.05% senior unsecured notes due 2018 |
250,000 | |||
7.00% senior unsecured notes due 2016 |
175,000 | |||
7.125% senior unsecured notes due 2025 |
85,000 | |||
695,000 | ||||
Unamortized debt discount |
1,563 | |||
Total long-term debt |
$ | 693,437 | ||
Our total long-term debt at December 31, 2009 had a carrying value of $693.4 million and a fair market value of $753.2 million. As of December 31, 2009, 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.
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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. In the event that we are not able to obtain replacement contracts, we would
seek to recover revenue shortfalls in a subsequent rate case.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page | ||||
41 | ||||
42 | ||||
43 | ||||
44 | ||||
46 | ||||
47 | ||||
48 | ||||
49 |
40
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MANAGEMENTS 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, 2009, based on the criteria set
forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control Integrated Framework. Previously, our management had concluded that our internal control
over financial reporting was effective for the period ended December 31, 2008. In the first quarter
of 2010, we identified a material weakness related to the manner in which we presented and
recognized pension and post retirement obligations in certain benefit plans for which our parent is
the plan sponsor.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a
material misstatement of the annual or interim financial statements will not be prevented or
detected on a timely basis.
As discussed further in Note 2 of the Notes to Consolidated Financial Statements, we previously recorded parent-allocated amounts related to these plans on a
single-employer basis rather than a multi-employer accounting model. As the plan assets are not
legally segregated and we are not contractually required to assume these obligations upon
withdrawal, we have now concluded that the appropriate accounting model for these historical
financial statements is a multi-employer model. The error was significant to the Statement of
Comprehensive Income for the period ended December 31, 2008. The impact of the correction
also increased Owners Equity and reduced non-current assets and liabilities. It did not have an
impact on our 2008 Net Income, nor did it have any impact on our 2008 Statement of Cash Flows.
Based upon our current assessment, which considered the material weakness described above, our
management concluded that our internal control over financial reporting was not effective at
December 31, 2008. Our management also concluded that our internal control over financial reporting
was not effective at December 31, 2009.
We have corrected our method of accounting to the multi-employer model, and this change is reflected in our financial statements for the period ended
December 31, 2009. We have also enhanced our controls that ensure proper selection and application
of generally accepted accounting principles.
This annual report does not include an attestation report of the companys registered public accounting firm regarding internal control over financial
reporting. Managements report was not subject to attestation by the companys registered public
accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit
the company to provide only managements report in this annual report.
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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, 2009 and 2008, 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, 2009. 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 Companys 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 Companys 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 Companys 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, 2009 and 2008, and the
consolidated results of its operations and its cash flows for each of the three years in the period
ended December 31, 2009, 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.
As discussed in Note 2 to the consolidated financial statements, the Company restated its consolidated balance sheet as of December 31, 2008 and the related consolidated
statements of comprehensive income, and owners equity for each of the two years then ended, as a
result of the correction of an error related to pension and other postretirement benefit
obligations in certain benefit plans for which their parent, The Williams Companies, Inc., is the plan
sponsor.
/s/ Ernst & Young |
Houston, Texas
February 23, 2010
February 23, 2010
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NORTHWEST PIPELINE GP
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
OPERATING REVENUES |
$ | 434,379 | $ | 434,854 | $ | 421,851 | ||||||
OPERATING EXPENSES: |
||||||||||||
General and administrative |
64,657 | 60,403 | 65,772 | |||||||||
Operation and maintenance |
71,085 | 72,831 | 66,847 | |||||||||
Depreciation |
86,373 | 86,184 | 84,731 | |||||||||
Regulatory credits |
(2,403 | ) | (2,617 | ) | (3,663 | ) | ||||||
Taxes, other than income taxes |
14,158 | 16,875 | 13,997 | |||||||||
Regulatory liability reversal |
| | (16,562 | ) | ||||||||
Total operating expenses |
233,870 | 233,676 | 211,122 | |||||||||
Operating income |
200,509 | 201,178 | 210,729 | |||||||||
OTHER INCOME net: |
||||||||||||
Interest income |
||||||||||||
Affiliated |
74 | 813 | 2,983 | |||||||||
Other |
16 | 6 | 2,681 | |||||||||
Allowance for equity funds used during construction |
1,996 | 812 | 2,091 | |||||||||
Miscellaneous other expense, net |
(135 | ) | (8 | ) | (517 | ) | ||||||
Contract termination income |
| | 18,199 | |||||||||
Total other income net |
1,951 | 1,623 | 25,437 | |||||||||
INTEREST CHARGES: |
||||||||||||
Interest on long-term debt |
44,439 | 42,290 | 46,828 | |||||||||
Other interest |
5,414 | 5,571 | 5,585 | |||||||||
Allowance for borrowed funds used
during construction |
(1,044 | ) | (431 | ) | (1,306 | ) | ||||||
Total interest charges |
48,809 | 47,430 | 51,107 | |||||||||
INCOME BEFORE INCOME TAXES |
153,651 | 155,371 | 185,059 | |||||||||
BENEFIT FOR INCOME TAXES (Note 7) |
| | (254,667 | ) | ||||||||
NET INCOME |
$ | 153,651 | $ | 155,371 | $ | 439,726 | ||||||
CASH DISTRIBUTIONS/DIVIDENDS |
$ | 135,000 | $ | 419,342 | $ | 109,770 | ||||||
See accompanying notes.
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NORTHWEST PIPELINE GP
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, | |||||||||
2009 | 2008 | ||||||||
(Restated) | |||||||||
ASSETS |
|||||||||
CURRENT ASSETS: |
|||||||||
Cash and cash equivalents |
$ | 402 | $ | 345 | |||||
Advances to affiliate |
| 65,977 | |||||||
Accounts receivable |
|||||||||
Trade |
40,442 | 40,116 | |||||||
Affiliated companies |
4,514 | 1,230 | |||||||
Materials and supplies, less reserves of $11 for 2009 and $111
for 2008 |
9,960 | 9,817 | |||||||
Exchange gas due from others |
4,089 | 17,000 | |||||||
Exchange gas offset |
10,288 | | |||||||
Prepayments and other |
4,241 | 5,985 | |||||||
Total current assets |
73,936 | 140,470 | |||||||
PROPERTY, PLANT AND EQUIPMENT, at cost |
2,887,021 | 2,765,520 | |||||||
Less Accumulated depreciation |
950,708 | 901,613 | |||||||
Total property, plant and equipment, net |
1,936,313 | 1,863,907 | |||||||
OTHER ASSETS: |
|||||||||
Deferred charges |
13,996 | 18,853 | |||||||
Regulatory assets |
57,032 | 55,582 | |||||||
Total other assets |
71,028 | 74,435 | |||||||
Total assets |
$ | 2,081,277 | $ | 2,078,812 | |||||
See accompanying notes.
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NORTHWEST PIPELINE GP
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, | |||||||||
2009 | 2008 | ||||||||
(Restated) | |||||||||
LIABILITIES AND OWNERS EQUITY |
|||||||||
CURRENT LIABILITIES: |
|||||||||
Accounts payable |
|||||||||
Trade |
$ | 17,552 | $ | 12,172 | |||||
Affiliated companies |
12,136 | 6,484 | |||||||
Accrued liabilities |
|||||||||
Taxes, other than income taxes |
8,176 | 10,019 | |||||||
Interest |
4,045 | 4,045 | |||||||
Employee costs |
9,435 | 10,426 | |||||||
Exchange gas due to others |
14,377 | 12,165 | |||||||
Exchange gas offset |
| 4,835 | |||||||
Other |
5,839 | 8,784 | |||||||
Total current liabilities |
71,560 | 68,930 | |||||||
LONG-TERM DEBT |
693,437 | 693,240 | |||||||
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES |
109,130 | 106,095 | |||||||
CONTINGENT LIABILITIES AND COMMITMENTS |
|||||||||
OWNERS EQUITY: |
|||||||||
Owners capital |
1,027,862 | 978,682 | |||||||
Loan to affiliate |
(105,431 | ) | (34,265 | ) | |||||
Retained earnings |
284,319 | 265,668 | |||||||
Accumulated other comprehensive income |
400 | 462 | |||||||
Total owners equity |
1,207,150 | 1,210,547 | |||||||
Total liabilities and owners equity |
$ | 2,081,277 | $ | 2,078,812 | |||||
See accompanying notes.
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NORTHWEST PIPELINE GP
CONSOLIDATED STATEMENTS OF OWNERS EQUITY
(Thousands of Dollars, Except Per Share Amounts)
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Restated) | (Restated) | |||||||||||
Common stock, par value $1 per share,
authorized, 1,000 shares |
||||||||||||
Balance at beginning of period, outstanding,
1,000 shares for 2007 |
$ | | $ | | $ | 1 | ||||||
Conversion to GP |
| | (1 | ) | ||||||||
Balance at end of period |
| | | |||||||||
Additional paid-in capital - |
||||||||||||
Balance at beginning of period |
| | 977,021 | |||||||||
Conversion to GP |
| | (977,021 | ) | ||||||||
Balance at end of period |
| | | |||||||||
Partners capital - |
||||||||||||
Balance at beginning of period |
978,682 | 977,022 | | |||||||||
Capital contribution from partner |
49,180 | 1,660 | | |||||||||
Conversion to GP |
| | 977,022 | |||||||||
Balance at end of period |
1,027,862 | 978,682 | 977,022 | |||||||||
Loans (to) from affiliate - |
||||||||||||
Balance at beginning of period |
(34,265 | ) | (29,186 | ) | (29,364 | ) | ||||||
Loans (to) from affiliate |
(71,166 | ) | (5,079 | ) | 178 | |||||||
Balance at end of period |
(105,431 | ) | (34,265 | ) | (29,186 | ) | ||||||
Retained earnings (deficit) - |
||||||||||||
Balance at beginning of period |
265,668 | 228,739 | (101,214 | ) | ||||||||
Net income |
153,651 | 155,371 | 439,726 | |||||||||
Cash distributions |
(135,000 | ) | (419,342 | ) | (109,770 | ) | ||||||
Sale of partnership interest |
| 300,900 | | |||||||||
Other |
| | (3 | ) | ||||||||
Balance at end of period |
284,319 | 265,668 | 228,739 | |||||||||
Accumulated other comprehensive income (loss) |
||||||||||||
Balance at beginning of period |
462 | 523 | 365 | |||||||||
Cash flow hedges: |
||||||||||||
Reclassification of gain into earnings |
(62 | ) | (61 | ) | (62 | ) | ||||||
Elimination of deferred income taxes |
| | 220 | |||||||||
Balance at end of period |
400 | 462 | 523 | |||||||||
Total owners equity |
$ | 1,207,150 | $ | 1,210,547 | $ | 1,177,098 | ||||||
See accompanying notes.
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NORTHWEST PIPELINE GP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Restated) | (Restated) | |||||||||||
Net Income |
$ | 153,651 | $ | 155,371 | $ | 439,726 | ||||||
Cash Flow Hedges: |
||||||||||||
Amortization of cash flow hedges |
(62 | ) | (61 | ) | (62 | ) | ||||||
Elimination of deferred income taxes |
| | 220 | |||||||||
Total comprehensive income |
$ | 153,589 | $ | 155,310 | $ | 439,884 | ||||||
See
accompanying notes.
47
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NORTHWEST PIPELINE GP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Restated) | (Restated) | |||||||||||
OPERATING ACTIVITIES: |
||||||||||||
Net Income |
$ | 153,651 | $ | 155,371 | $ | 439,726 | ||||||
Adjustments
to reconcile to net cash provided by operating activities - |
||||||||||||
Depreciation |
86,373 | 86,184 | 84,731 | |||||||||
Regulatory credits |
(2,403 | ) | (2,617 | ) | (3,663 | ) | ||||||
Gain on sale of property, plant and equipment |
(508 | ) | (378 | ) | | |||||||
Provision (benefit) for deferred income taxes |
| | (289,229 | ) | ||||||||
Amortization of deferred charges and credits |
12,561 | 8,589 | 9,783 | |||||||||
Allowance for equity funds used during construction |
(1,996 | ) | (812 | ) | (2,091 | ) | ||||||
Reserve for doubtful accounts |
| (7 | ) | (46 | ) | |||||||
Regulatory liability reversal |
| | (16,562 | ) | ||||||||
Contract termination income |
| | (6,045 | ) | ||||||||
Cash
provided (used) by changes in current assets and liabilities: |
||||||||||||
Trade accounts receivable |
(326 | ) | 580 | (8,413 | ) | |||||||
Affiliated receivables, including income taxes in 2007 |
(3,284 | ) | 2,284 | (2,923 | ) | |||||||
Exchange gas due from others |
2,623 | 4,583 | (1,654 | ) | ||||||||
Materials and supplies |
(143 | ) | 527 | (331 | ) | |||||||
Other current assets |
1,744 | 943 | 1,017 | |||||||||
Trade accounts payable |
(828 | ) | (2,599 | ) | 4,653 | |||||||
Affiliated payables, including income taxes in 2007 |
275 | (6,572 | ) | (5,259 | ) | |||||||
Exchange gas due to others |
(2,623 | ) | (4,583 | ) | 1,654 | |||||||
Other accrued liabilities |
(533 | ) | 3,083 | 2,105 | ||||||||
Changes in noncurrent assets and liabilities: |
||||||||||||
Deferred charges |
(4,580 | ) | (423 | ) | (9,769 | ) | ||||||
Other deferred credits |
(5,205 | ) | (5,139 | ) | 7,673 | |||||||
Net cash provided by operating activities |
234,798 | 239,014 | 205,357 | |||||||||
FINANCING ACTIVITIES: |
||||||||||||
Proceeds from issuance of long-term debt |
| 249,333 | 434,362 | |||||||||
Retirement of long-term debt |
| (250,000 | ) | (252,867 | ) | |||||||
Early retirement of long-term debt |
| | (175,000 | ) | ||||||||
Debt issuance costs |
| (2,027 | ) | (2,059 | ) | |||||||
Premium on early retirement of long-term debt |
| | (7,111 | ) | ||||||||
Capital contribution from parent |
49,180 | 1,660 | | |||||||||
Proceeds from sale of partnership interest |
| 300,900 | | |||||||||
Distributions paid |
(135,000 | ) | (419,342 | ) | (109,770 | ) | ||||||
Changes in cash overdrafts |
2,212 | (7,372 | ) | (30,078 | ) | |||||||
Net cash used in financing activities |
(83,608 | ) | (126,848 | ) | (142,523 | ) | ||||||
INVESTING ACTIVITIES: |
||||||||||||
Property, plant and equipment - |
||||||||||||
Capital expenditures* |
(152,580 | ) | (88,478 | ) | (156,761 | ) | ||||||
Proceeds from sales |
2,234 | 3,065 | 2,257 | |||||||||
Proceeds from sale of Parachute facilities |
| | 79,770 | |||||||||
Repayments from (advances to) affiliates |
(787 | ) | (26,905 | ) | 10,908 | |||||||
Net cash used in investing activities |
(151,133 | ) | (112,318 | ) | (63,826 | ) | ||||||
NET INCREASE
(DECREASE) IN CASH AND CASH EQUIVALENTS |
57 | (152 | ) | (992 | ) | |||||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
345 | 497 | 1,489 | |||||||||
CASH AND CASH EQUIVALENTS AT END OF YEAR |
$ | 402 | $ | 345 | $ | 497 | ||||||
* Increases to property, plant and equipment |
$ | (156,576 | ) | $ | (78,566 | ) | $ | (157,163 | ) | |||
Changes in related accounts payable and accrued liabilities |
3,996 | (9,912 | ) | 402 | ||||||||
Capital expenditures |
$ | (152,580 | ) | $ | (88,478 | ) | $ | (156,761 | ) | |||
Supplemental disclosures of non-cash transactions: |
||||||||||||
Adjustment to owners equity for benefit plans correction |
$ | (4,402 | ) | $ | (5,079 | ) | $ | 178 | ||||
Advances to affiliates reclassified to owners equity |
66,764 | | | |||||||||
See accompanying notes.
48
Table of Contents
NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate Structure and Control
Northwest Pipeline GP (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
we are a general partnership, we are not subject to federal and state income taxes. Coincident
with our conversion to a general partnership 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 was
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 December 31, 2009.
On
February 17, 2010, Williams completed a strategic restructuring,
pursuant to which Williams contributed its ownership in WGPC Holdings LLC to Williams Partners L.P. (WPZ), a publicly traded
Delaware limited partnership which is controlled by and consolidated
with Williams. Through its ownership interests in each
of our partners, Williams indirectly owns 71.3 percent of Northwest as of February 17, 2010.
On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the
outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the
successful consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in Northwest
and Williams will hold an approximate 80 percent interest in WPZ.
Northwest is not an employer. Services are provided to Northwest by Northwest Pipeline
Services LLC, a consolidated affiliate. 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
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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.
The Accounting Standards Codification Regulated Operations (Topic 980) provides that
rate-regulated public utilities 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 Topic 980, 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, 2009 and 2008, we had
approximately $59.2 million and $57.8 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 $15.1
million and $14.7 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.
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; and 5) 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 2.77 percent, 2.79 percent and 2.76 percent for 2009, 2008 and 2007,
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 Expansion Projects levelized depreciation as a regulatory asset
with the offsetting credit recorded to a regulatory credit on the accompanying Income Statement.
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We recorded regulatory credits totaling $2.4 million in 2009, $2.6 million in 2008, and $3.7
million in 2007 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 $30.8 million at December 31, 2009, and $28.4 million at
December 31, 2008. 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, 2009 and 2008 were $33.8 million and $26.8 million, respectively. The full
amount of the regulatory asset is expected to be recovered in future rates.
The negative salvage component of accumulated depreciation ($29.5 million and $25.6 million at
December 31, 2009 and 2008, 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 2009, 2008 and
2007. Equity AFUDC of $2.0 million, $0.8 million and $2.1 million for 2009, 2008 and 2007,
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 do not record 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 0.05 percent and zero
percent at December 31, 2009 and 2008, respectively.
In accordance with Williams restructuring of its business, our participation in the Williams
cash management program was terminated. In February 2010, our management committee authorized
a cash distribution which included the amount of our outstanding advances as of January 31, 2010.
Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our
Owners
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Equity as the advances will not be available to us as working capital. As a result of the
restructuring, we will become a participant in the WPZ cash management program.
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 managements judgment, that the carrying value of such assets may not be recoverable. When such
a determination has been made, managements 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 managements estimate of undiscounted future cash
flows used to determine recoverability of an asset and the estimate of an assets 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 7.)
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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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 reservation charge based on the volume of contracted
capacity and a volumetric charge based on the volume of gas delivered, both at rates specified in
our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period
regardless of the volume of natural gas that is transported or stored. Revenues for volumetric
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 the issuance of final orders by the FERC in pending rate proceedings. We
record estimates of rate refund liabilities considering our and third-party regulatory proceedings,
advice of counsel and other risks. At December 31, 2009, 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 $44.5 million, $43.1 million and $49.7 million in 2009, 2008
and 2007, respectively.
Subsequent Events
We have evaluated our disclosure of subsequent events through the time of filing this Form
10-K with the SEC on February 23, 2010.
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Accounting Standards Issued But Not Yet Adopted
In June 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) No. 2009-17, Consolidations (Topic 810) Improvements to Financial Reporting by
Enterprises Involved with Variable Interest Entities (ASU No. 2009-17). This Update amends
Interpretation 46(R) to require an entity to perform a qualitative analysis to determine whether
the entitys variable interest or interests give it a controlling financial interest in a VIE. This
analysis identifies the primary beneficiary of a VIE as the entity that has both the power to
direct the activities that most significantly impact the VIEs economic performance and the
obligation to absorb losses or the right to receive benefits of the VIE. ASU No. 2009-17 amends
Interpretation 46(R) to replace the quantitative-based risks and rewards approach previously
required for determining the primary beneficiary of a VIE. ASU No. 2009-17 is effective as of the
beginning of an entitys first annual reporting period that begins after November 15, 2009 and for
interim periods within that first annual reporting period. Earlier application is prohibited. We
will assess the application of this Statement on our Consolidated Financial Statements.
In January 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures
(Topic 820) Improving Disclosures about Fair Value Measurements. This Update requires new
disclosures regarding the amount of transfers in or out of levels 1 and 2 along with the reason for
such transfers and also requires a greater level of disaggregation when disclosing valuation
techniques and inputs used in estimating level 2 and level 3 fair value measurements. This Update
also includes conforming amendments to the guidance on employers disclosures about postretirement
benefit plan assets. The disclosures will be required for reporting beginning in the first quarter
of 2010. Also, beginning with the first quarter of 2011, the Standard requires additional
categorization of items included in the rollforward of activity for level 3 inputs on a gross
basis. We are assessing the application of this Standard to disclosures in our Consolidated
Financial Statements.
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
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.
2. RESTATEMENT
On January 20, 2010, we concluded that our financial statements for the year ended December
31, 2008 should be restated due to the manner in which we have presented and recognized pension and
postretirement obligations in certain benefit plans for which Williams is the plan sponsor. We
have previously recorded allocated amounts related to these plans on a single-employer basis rather
than a multi-employer accounting model. As the plan assets are not legally segregated and we are
not contractually required to assume these obligations upon withdrawal, we have now concluded that
the appropriate accounting model for these historical financial statements is a multi-employer
model.
We participate in pension and postretirement benefit plans sponsored by Williams. However, we
have historically accounted for these plans as if they were our own. We have now determined that
ASC 715-30-55-63 requires us to account for the plans as if we are a participant in a
multi-employer plan. This error in methodology had the most significant impact to our financial
statements for the year ended December 31, 2008. In that year, we recognized a significant
Williams-allocated actuarial loss on our Consolidated Balance Sheet, Consolidated Statement of
Owners Equity and Consolidated Statement of Comprehensive Income. We have determined that the
error was significant to the Statement of Comprehensive Income for the year ended December 31,
2008. For this period, Comprehensive Income should have approximated Net Income. The effect of
the adjustments to Comprehensive Income is an
increase of $39.4 million in 2008 and $2.4 million in 2007, respectively. The impact of this error
correction also increased Owners Equity and reduced noncurrent assets and liabilities at December
31,
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2008, with an offsetting impact to Loans to Affiliate, which is presented as a reduction to Owners
Equity (See Note 1). The impact of the error correction did not have an impact on our 2008 or 2007
Net Income as our expense recognized approximated our contributions to the Williams-sponsored
plans, nor did it have any impact on our 2008 or 2007 Consolidated Statements of Cash Flows.
The following schedules reconcile the amounts previously reported in our consolidated
Financial Statements as of December 31, 2008 and for the years ended December 31, 2008 and 2007.
December 31, | ||||
2008 | ||||
Consolidated Balance Sheet: |
||||
Deferred charges, as previously reported |
$ | 22,213 | ||
Correction to remove benefit plan assets |
3,360 | |||
Deferred charges, as restated |
$ | 18,853 | ||
Total other assets, as previously reported |
$ | 77,795 | ||
Correction to remove benefit plan assets |
3,360 | |||
Total other assets, as restated |
$ | 74,435 | ||
Total assets, as previously reported |
$ | 2,082,172 | ||
Correction to remove benefit plan assets |
3,360 | |||
Total assets, as restated |
$ | 2,078,812 | ||
Accrued liabilities - |
||||
Employee costs, as previously reported |
$ | 10,505 | ||
Correction to remove benefit plan liabilities |
79 | |||
Employee costs, as restated |
$ | 10,426 | ||
Total current liabilities, as previously reported |
$ | 69,009 | ||
Correction to remove benefit plan liabilities |
79 | |||
Total current liabilities as restated |
$ | 68,930 | ||
Deferred credits and other noncurrent liabilities, as previously reported |
$ | 135,209 | ||
Correction to remove benefit plan liabilities |
29,114 | |||
Deferred credits and other noncurrent liabilities, as restated |
$ | 106,095 | ||
Loan to affiliate, as previously reported |
$ | | ||
Correction to remove benefit plan assets and liabilities |
34,265 | |||
Loan to affiliate, as restated |
$ | (34,265 | ) | |
Accumulated other comprehensive loss, as previously reported |
$ | (59,636 | ) | |
Correction to remove benefit plans |
(60,098 | ) | ||
Accumulated other comprehensive income, as restated |
$ | 462 | ||
Total owners equity, as previously reported |
$ | 1,184,714 | ||
Correction to remove benefit plan assets, liabilities, and other
comprehensive loss |
(25,833 | ) | ||
Total owners equity, as restated |
$ | 1,210,547 | ||
Total liabilities and owners equity, as previously reported |
$ | 2,082,172 | ||
Correction to remove benefit plan assets, liabilities, and other
comprehensive loss |
3,360 | |||
Total liabilities and owners equity, as restated |
$ | 2,078,812 | ||
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Years Ended December 31, | ||||||||
2008 | 2007 | |||||||
Consolidated
Statements of Owners Equity:
|
||||||||
Loan to affiliate -
|
||||||||
Balance at beginning of period, as previously
reported |
$ | | $ | | ||||
Cumulative amount of benefit plans correction |
| (29,364 | ) | |||||
Balance at beginning of period, as restated |
(29,186 | ) | (29,364 | ) | ||||
Loans (to) from affiliate |
(5,079 | ) | 178 | |||||
Balance at end of period |
$ | (34,265 | ) | $ | (29,186 | ) | ||
Accumulated other comprehensive income (loss)
|
||||||||
Balance at beginning of period, as previously
stated |
$ | | $ | (17,863 | ) | |||
Cumulative amount of benefit plans correction |
| 18,228 | ||||||
Balance at beginning of period, as restated |
523 | 365 | ||||||
Cash flow hedges: |
||||||||
Reclassification of gain into earnings |
(61 | ) | (62 | ) | ||||
Elimination of deferred income taxes |
| 220 | ||||||
Balance at end of period |
$ | 462 | $ | 523 | ||||
Years Ended December 31, | ||||||||
2008 | 2007 | |||||||
Consolidated Statements of Comprehensive Income: |
||||||||
Total comprehensive income, as previously reported |
$ | 115,880 | $ | 437,444 | ||||
Correction to remove benefit plans |
(39,430 | ) | (2,440 | ) | ||||
Total comprehensive income, as restated |
$ | 155,310 | $ | 439,884 | ||||
3. 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 leased the facilities back to us,
and we continued to operate the facilities under the FERC certificate. Under the terms of the
lease, we paid
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Parachute 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. The lease was terminated on
August 1, 2009, and Parachute assumed full operational control and responsibility for the Parachute
Lateral.
4. CONTINGENT LIABILITIES AND COMMITMENTS
Legal Proceedings
We are a party to legal, administrative, and regulatory proceedings arising in the ordinary
course of business.
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 we are 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 Washingtons
current environmental standards. At December 31, 2009, we had accrued liabilities totaling
approximately $7.8 million for these costs which are expected to be incurred through 2015. 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 issued new air quality standards for ground level ozone, but in
September 2009, the EPA announced that it would reconsider those standards. In January 2010, the
EPA proposed standards more stringent than the March 2008 standards. The EPA expects that these
proposed standards will be final in August 2010 and that new eight-hour ozone non-attainment areas
will be designated in July 2011. The new standards and non-attainment areas will likely impact the
operations of our interstate gas pipeline and cause us to incur additional capital expenditures.
At this time, we are unable to estimate the cost of the additions that may be required to meet
these regulations. We expect that costs associated with these compliance efforts will be
recoverable through rates.
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 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 primarily capital in nature and range between $65
million and $85 million
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over the remaining assessment period of 2010 through 2012. 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 liquidity or financial position.
Other Commitments
We have commitments for construction and acquisition of property, plant and equipment of
approximately $13.4 million at December 31, 2009.
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 accordance with Williams restructuring of its business, our participation in the Williams
cash management program was terminated. In February 2010, our management committee authorized
a cash distribution which included the amount of our outstanding advances as of January 31, 2010.
Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our
Owners Equity as the advances will not be available to us as working capital. As a result of the
restructuring, we will become a participant in the WPZ cash management program.
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. During the year
ended December 31, 2009, we declared and paid equity distributions of $135.0 million to our
partners. In January 2010, we declared and paid equity distributions of $36.0 million to our
partners.
5. DEBT, FINANCING ARRANGEMENTS AND LEASES
Debt Covenants
Our debt agreements contain restrictions on our ability to incur secured debt beyond certain
levels.
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Long-Term Debt
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.
Long-term debt consists of the following:
December 31, | ||||||||
2009 | 2008 | |||||||
(Thousands of Dollars) | ||||||||
5.95%, payable 2017 |
$ | 184,535 | $ | 184,471 | ||||
6.05%, payable 2018 |
249,440 | 249,374 | ||||||
7%, payable 2016 |
174,643 | 174,587 | ||||||
7.125%, payable 2025 |
84,819 | 84,808 | ||||||
Total long-term debt |
$ | 693,437 | $ | 693,240 | ||||
As of December 31, 2009, cumulative sinking fund requirements and other maturities of
long-term debt (at face value) for each of the next five years are as follows:
(Thousands of Dollars) | ||||
2010 |
$ | | ||
2011 |
| |||
2012 |
| |||
2013 |
| |||
2014 |
| |||
Thereafter |
695,000 | |||
Total |
$ | 695,000 | ||
Line-of-Credit Arrangements
Williams has an unsecured, $1.5 billion credit facility (Credit Facility) with a maturity date
of May 1, 2012. Prior to Williams restructuring, we had access to $400 million under the Credit Facility to the extent not
otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit
Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we
expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million.
Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lenders
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) based on the unused portion of the Credit Facility. The margins and commitment fee
are generally based on the specific borrowers senior unsecured long-term debt ratings. As of
December 31, 2009, there were no letters of credit issued by the participating institutions and no
revolving credit loans outstanding. We did not access the Credit
Facility in 2009 or 2008.
Significant financial covenants under the Credit Facility include the following:
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| Williams ratio of debt to capitalization must be no greater than 65 percent. Williams was in compliance with this covenant at December 31, 2009. | ||
| Our ratio of debt to capitalization and that of another participating subsidiary of Williams must be no greater than 55 percent. We were in compliance with this covenant at December 31, 2009. |
On
February 17, 2010, Williams completed a strategic
restructuring, pursuant to which Williams contributed
substantially all of its domestic midstream and pipeline businesses, which includes
us, into WPZ. We are now a partially-owned subsidiary of WPZ. As part of the restructuring, we
were removed as borrowers under the Credit Facility, and on February 17, 2010, we entered into a
new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with
WPZ and Transcontinental Gas Pipe Line Company, LLC (Transco), as co-borrowers, and Citibank N.A.,
as administrative agent, and certain other lenders named therein. The full amount of the New
Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We
may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by
WPZ and Transco. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the
term loan outstanding under its existing senior unsecured credit agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to,
at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.s adjusted base
rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable
margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent,
(ii) Citibank, N.A.s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent.
WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit
Facility. The applicable margin and the commitment fee are determined by reference to a pricing
schedule based on a borrowers senior unsecured debt ratings.
The
New Credit Facility contains various covenants that limit, among other things, a
borrowers and its respective subsidiaries ability to incur indebtedness, grant certain liens
supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter
into certain affiliate transactions, make certain distributions during an event of default, and
allow any material change in the nature of its business.
Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before
Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit
Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and
our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt)
is not permitted to be greater than 55 percent. Each of the above ratios will be tested beginning
June 30, 2010 at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a
rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default
relating to non-payment of principal, interest or fees, inaccuracy of representations and
warranties in any material respect when made or when deemed made,
violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied
judgments and a change of control. If an event of default with respect to a borrower occurs under
the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers
and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility
and exercise other rights and remedies.
Leases
Our leasing arrangements include mostly premise and equipment leases that are classified as
operating leases.
Through September 30, 2009, the major operating lease was a leveraged lease for our
headquarters building, which became effective during 1982. The agreement had 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 exercised our option to renew the term of the lease for
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NORTHWEST PIPELINE GP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately 9 years, beginning October 1, 2009. The major component of the lease
payment was set through the initial and first renewal terms of the lease. Various purchase options
existed under the building lease, including options involving adverse regulatory developments.
Through September 30, 2009, we subleased portions of our headquarters building to third parties
under agreements with varying terms. This leveraged lease for our headquarters building was assigned to a third party
effective October 1, 2009.
Effective October 1, 2009, we entered into an agreement to lease office space from a third
party. The agreement has an initial term of approximately 10 years, with an option to renew for an
additional 5 or 10 year term.
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:
(Thousands of Dollars) | ||||
2010 |
$ | 2,284 | ||
2011 |
2,284 | |||
2012 |
2,284 | |||
2013 |
2,284 | |||
2014 |
2,285 | |||
Total |
$ | 11,421 | ||
Operating lease rental expense, net of sublease revenues, amounted to $3.6 million, $4.9
million, and $4.9 million for 2009, 2008 and 2007, respectively.
On December 31, 2007, in connection with the sale of Parachute to an affiliate of Williams,
Parachute leased the facilities back to us. We continued to operate the facilities under the FERC
certificate through July 31, 2009. The lease terminated on August 1, 2009. Under the terms of the
lease, we paid 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.
6. EMPLOYEE BENEFIT PLANS
Pension and other postretirement benefit plans
We participate in pension and other postretirement benefit plans sponsored by Williams. We
account for these plans on the multi-employer accounting model in which we expense the amounts
billed to us by Williams or other Williams affiliates for our participation in these plans. We
recognized pension expense of $7.5 million in 2009, $3.5 million in 2008 and $4.0 million in 2007.
No other postretirement benefit expense was recognized in 2009, 2008 or 2007.
Defined contribution plan
Employees participate in a Williams defined contribution plan. We recognized compensation
expense of $2.2 million in 2009, $2.1 million in 2008 and $2.0 million in 2007 for Williams
company matching contributions to this plan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Compensation
Plan Information
The Williams Companies, Inc. 2007 Incentive Plan (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 the options. We
are also billed for our proportionate share of both Williams Gas Pipeline Company, LLCs (WGP) and
Williams stock-based compensation expense through various allocation processes.
Accounting for Stock-Based Compensation
Compensation cost for share-based awards is based on the grant date fair value. The
performance targets for certain performance based restricted stock units have not been established
and therefore, expense is not currently recognized. Expense associated with these
performance-based awards will be recognized in future periods when performance targets are
established.
Total stock-based compensation expense, included in administrative and general expenses, for
the years ended December 31, 2009, 2008 and 2007 was $1.3 million, $1.0 million and $1.1 million,
respectively, excluding amounts allocated from WGP and Williams.
7. INCOME TAXES
Following our conversion to a general partnership on October 1, 2007, we are no longer subject
to income tax.
The benefit for income taxes includes:
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Thousands of Dollars) | ||||||||||||
Current: |
||||||||||||
Federal |
$ | | $ | | $ | 30,888 | ||||||
State |
| | 3,674 | |||||||||
| | 34,562 | ||||||||||
Deferred: |
||||||||||||
Federal |
| | (258,459 | ) | ||||||||
State |
| | (30,770 | ) | ||||||||
| | (289,229 | ) | |||||||||
Total benefit |
$ | | $ | | $ | (254,667 | ) | |||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the statutory Federal income tax rate to the benefit for income taxes is
as follows:
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Thousands of Dollars) | ||||||||||||
Provision at statutory
Federal income tax rate of 35 percent (1)
|
$ | | $ | | $ | 52,831 | ||||||
Increase in tax provision
resulting from -
|
||||||||||||
State income taxes
net of Federal tax benefit
|
| | 3,948 | |||||||||
Book/tax basis reconciliation
adjustment
|
| | | |||||||||
Other net
|
| | 330 | |||||||||
|
||||||||||||
|
||||||||||||
Provision for income
taxes prior to conversion from a corporation to a partnership
|
$ | | $ | | $ | 57,109 | ||||||
|
||||||||||||
|
||||||||||||
Effective tax rate
prior to conversion from a corporation to a partnership
|
| | 37.83 | % | ||||||||
|
||||||||||||
|
||||||||||||
Provision for income
taxes prior to conversion from a corporation to a partnership
|
$ | | $ | | $ | 57,109 | ||||||
Conversion from corporation
to partnership
|
| | (311,776 | ) | ||||||||
|
||||||||||||
|
||||||||||||
Total benefit for income
taxes
|
$ | | $ | | $ | (254,667 | ) | |||||
|
(1) | Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. The provision for income taxes shown herein for 2007 reflects the provision through September 30, 2007. Subsequent to the conversion to a general partnership on October 1, 2007, all deferred income taxes were eliminated and we no longer provide for income taxes. |
No cash payments for income taxes were made to or received from Williams in 2009 or 2008. Net
cash payments made to Williams for income taxes were $37.7 million in 2007.
8. FINANCIAL INSTRUMENTS
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.
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 $693.4 million and
$753.2 million, respectively, at December 31, 2009, and $693.2 million and $572.0 million,
respectively, at December 31, 2008.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. 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:
Year Ended December 31, | ||||||||||||
2009 | 2008 | 2007 | ||||||||||
(Thousands of Dollars) | ||||||||||||
Puget Sound Energy, Inc. |
$ | 94,508 | $ | 89,988 | $ | 85,059 | ||||||
Northwest Natural Gas Co. |
49,256 | (a) | 48,648 |
(a) | Under 10 percent in 2008 |
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, 2009 and 2008, the advances due to us by Williams totaled
approximately $66.8 million and $66.0 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 0.05
percent and zero percent at December 31, 2009 and 2008, respectively. We received interest income
from advances to Williams of $74 thousand, $813 thousand, and $2,983 thousand during 2009, 2008 and
2007, respectively. Such interest income is included in Other Income net: Interest income
Affiliated on the accompanying Consolidated Statements of Income. In accordance with Williams
restructuring of its business, our participation in the
Williams cash management program was
terminated. In February 2010, our management committee authorized a cash distribution which
included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance
outstanding at December 31, 2009 is reflected as a reduction of our Owners Equity as the advances
will not be available to us as working capital. As a result of the restructuring, we will become a
participant in the WPZ cash management program.
Williams corporate overhead expenses allocated to us were $19.7 million, $16.9 million and
$19.6 million for 2009, 2008 and 2007, 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 $16.3 million, $15.8 million and $16.6 million for 2009, 2008 and 2007, respectively.
These expenses are included in General and administrative expense on the accompanying
Consolidated Statements of Income. A portion of such expenses relates to the compensation of our
principal executive officer, principal financial officer and three other most highly compensated
officers (our Named Executive Officers or NEOs). Please see Item 11. Executive Compensation, for
more information about the compensation of such NEOs.
During the periods presented, our revenues include transportation transactions and rental of
communication facilities with subsidiaries of Williams. Combined revenues for these activities
totaled $9.9 million, $14.8 million and $11.8 million for 2009, 2008 and 2007, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
From January 2008 through July 2009, we leased the Parachute Lateral facilities from an
affiliate. Under the terms of the operating lease, we paid 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 $5.9 million and $10.1 million for the
years ended December 31, 2009 and 2008, respectively, is included in Operation and maintenance
expense on the accompanying Consolidated Statements of Income. The lease was terminated on August
1, 2009.
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.
10. ASSET RETIREMENT OBLIGATIONS
During 2009 and 2008, we adjusted the ARO liability and Property, Plant and Equipment for a
change in the inflation and discount rates.
During 2009 and 2008, our overall asset retirement obligation changed as follows (in
thousands):
2009 | 2008 | |||||||
Beginning balance |
$ | 82,666 | $ | 50,423 | ||||
Accretion |
6,068 | 4,341 | ||||||
New obligations |
2,594 | 116 | ||||||
Changes in estimates of existing obligations |
(4,579 | ) | 27,790 | |||||
Obligation settled |
| (4 | ) | |||||
Ending Balance |
$ | 86,749 | $ | 82,666 | ||||
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.
11. REGULATORY ASSETS AND LIABILITIES
Our
regulatory assets and liabilities result from our application of the
provisions of Topic 980 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, 2009 and 2008:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2009 | 2008 | |||||||
(Restated) | ||||||||
(Thousands of Dollars) | ||||||||
Current regulatory assets environmental costs |
$ | 2,200 | $ | 2,200 | ||||
Noncurrent regulatory assets |
||||||||
Environmental costs |
3,590 | 5,790 | ||||||
Grossed-up deferred taxes on equity funds used during construction |
18,346 | 19,234 | ||||||
Levelized incremental depreciation |
30,801 | 28,397 | ||||||
Asset retirement obligations, net |
4,295 | 1,189 | ||||||
Other post-employment benefits |
| 972 | ||||||
Total noncurrent regulatory assets |
57,032 | 55,582 | ||||||
Total regulatory assets |
$ | 59,232 | $ | 57,782 | ||||
Noncurrent regulatory liabilities |
||||||||
Postretirement benefits |
$ | 15,134 | $ | 14,652 | ||||
Total regulatory liabilities |
$ | 15,134 | $ | 14,652 | ||||
12. QUARTERLY INFORMATION (UNAUDITED)
The following is a summary of unaudited quarterly financial data for 2009 and 2008:
Quarter of 2009 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
(Thousands of Dollars) | ||||||||||||||||
Operating revenues |
$ | 111,548 | $ | 107,756 | $ | 106,615 | $ | 108,460 | ||||||||
Operating income |
53,152 | 47,013 | 49,145 | 51,199 | ||||||||||||
Net income |
40,908 | 35,162 | 38,260 | 39,321 |
Quarter of 2008 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
(Thousands of Dollars) | ||||||||||||||||
Operating revenues |
$ | 107,405 | $ | 106,450 | $ | 108,542 | $ | 112,457 | ||||||||
Operating income |
49,166 | 46,676 | 53,042 | 52,294 | ||||||||||||
Net income |
38,158 | 35,685 | 41,236 | 40,292 |
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Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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 13a15(e) and
15d15(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. Previously, our management had concluded that our Disclosure
Controls were effective at a reasonable assurance level at December 31, 2008. Based upon our
current evaluation, which considered the material weakness described in Managements Report on
Internal Control Over Financial Reporting, our Senior Vice President and our Vice President and
Treasurer concluded that these Disclosure Controls were not effective at a reasonable assurance
level at December 31, 2008. Our management also concluded that these Disclosure Controls were not
effective at a reasonable assurance level at December 31, 2009.
As discussed in Item 8. Financial Statements and Supplementary DataManagements Report on
Internal Control Over Financial Reporting and Note 2 of the Notes to Consolidated
Financial Statements, in the first quarter of 2010, we identified a material weakness related to
the manner in which we presented and recognized pension and postretirement obligations in certain
benefit plans for which our parent is the plan sponsor. We have corrected our method of accounting
for the parent-allocated amounts related to pension and postretirement plans to the multi-employer
model. We have also enhanced our controls that ensure proper selection and application of generally
accepted accounting principles.
Managements Annual Report on Internal Control over Financial Reporting
See report set forth 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 2009 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls over financial reporting.
However, in the first quarter of 2010, we enhanced our controls that ensure proper selection and
application of generally accepted accounting principles. We also made the change described above in
our method of accounting for parent-allocated amounts related to certain pension and post
retirement plans and that change is reflected in our financial statements for the period ended
December 31, 2009.
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PART III
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.
Name | Age | Position | ||||
Phillip D. Wright
|
54 | Senior Vice President and Management Committee Member (Principal Executive Officer) | ||||
Donald R. Chappel
|
58 | Management Committee Member | ||||
Steven J. Malcolm
|
61 | Chief Executive Officer | ||||
Richard D. Rodekohr
|
51 | Vice President and Treasurer (Principal Financial Officer) | ||||
Allison G. Bridges
|
50 | Vice President | ||||
Randall L. Barnard
|
51 | Vice President | ||||
Lawrence G. Hjalmarson
|
55 | Vice President | ||||
Randall R. Conklin
|
53 | Vice President and General Counsel | ||||
Frank J. Ferazzi
|
53 | Vice President |
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, and Williams Partners GP LLC, the general
partner of WPZ.
Mr. Chappel has served as a member of our management committee since October 1, 2007. Since
2003, Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams.
Mr. Chappel is Chief Financial Officer and a director of Williams Pipeline GP LLC, the general
partner of WMZ. Mr. Chappel is also Chief Financial Officer and a 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 and Chairman 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.
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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, General Counsel, and Assistant Secretary since
October 1, 2007. Mr. Conklin served as Vice President, General Counsel, and Secretary of Northwest
Pipeline Corporation from April 1, 2003 to September 30, 2007 and as Senior Vice President, General
Counsel, and Secretary 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://www.williams.com under the heading Corporate
Responsibility Corporate Governance Ethics and Compliance Program Williams Code of
Business Conduct.
Corporate Governance
We do not have an audit committee, nominating and governance committee, or compensation
committee.
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 or one of its subsidiaries. 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 2010 annual meeting of
stockholders which will be available upon its filing on the SECs 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.
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Executive Compensation
The summary compensation table includes amounts allocated to Northwest by Williams for
services provided by our executive officers.
2009 Summary Compensation Table
Change in | ||||||||||||||||||||||||||||||||||||
Pension Value | ||||||||||||||||||||||||||||||||||||
and | ||||||||||||||||||||||||||||||||||||
Nonqualified | ||||||||||||||||||||||||||||||||||||
Non-Equity | Deferred | |||||||||||||||||||||||||||||||||||
Stock | Option | Incentive Plan | Compensation | All Other | ||||||||||||||||||||||||||||||||
Name | Year | Salary | Bonus | Awards | Awards | Compensation | Earnings | Compensation | Total | |||||||||||||||||||||||||||
Phillip D. Wright |
2009 | $ | 111,204 | $ | | $ | 96,651 | $ | 148,250 | $ | 120,287 | $ | 89,934 | $ | 4,607 | $ | 570,933 | |||||||||||||||||||
Senior Vice President |
2008 | 130,579 | | (21,196 | ) | 84,665 | 146,250 | 100,148 | 2,626 | 443,072 | ||||||||||||||||||||||||||
(Principal Executive Officer) |
2007 | 92,681 | | 408,204 | 66,898 | 129,929 | 13,203 | 1,902 | 712,817 | |||||||||||||||||||||||||||
Richard D,
Rodekohr |
2009 | 48,225 | | 17,480 | 22,518 | 33,606 | 36,789 | 3,109 | 161,727 | |||||||||||||||||||||||||||
Vice President and Treasurer |
2008 | 53,474 | | 14,028 | 21,662 | 35,696 | 40,088 | 3,396 | 168,344 | |||||||||||||||||||||||||||
(Principal Financial Officer) |
2007 | 44,358 | | 100,495 | 22,953 | 36,913 | (121 | ) | 2,966 | 207,564 | ||||||||||||||||||||||||||
Allison G. Bridges |
2009 | 259,615 | | 73,173 | 96,301 | 202,488 | 188,741 | 15,105 | 835,423 | |||||||||||||||||||||||||||
Vice President |
2008 | 248,500 | | 12,850 | 94,020 | 196,013 | 217,251 | 11,905 | 780,539 | |||||||||||||||||||||||||||
2007 | 235,211 | | 421,027 | 95,960 | 196,919 | 1,832 | 13,895 | 964,844 | ||||||||||||||||||||||||||||
Randall L. Barnard |
2009 | 21,527 | | 6,473 | 8,366 | 19,277 | 16,355 | 1,044 | 73,042 | |||||||||||||||||||||||||||
Vice President |
2008 | 32,038 | | 1,318 | 12,783 | 28,739 | 23,379 | 1,529 | 99,786 | |||||||||||||||||||||||||||
2007 | 72,584 | | 142,715 | 33,037 | 76,975 | 3,091 | 3,644 | 332,046 | ||||||||||||||||||||||||||||
Lawrence G. Hjalmarson |
2009 | 8,964 | | 3,202 | 4,444 | 6,079 | 6,370 | 618 | 29,677 | |||||||||||||||||||||||||||
Vice President |
2008 | 10,823 | | 2,563 | 5,729 | 7,098 | 6,573 | 606 | 33,392 | |||||||||||||||||||||||||||
2007 | 68,301 | | 16,427 | 22,957 | 51,332 | 1,345 | 5,009 | 165,371 |
Compensation Committee Interlocks and Insider Participation
We do not maintain a compensation committee. Our executive officers during 2009 were employees
of Williams or one
of its subsidiaries, 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 or one
of its subsidiaries, and receive no compensation
for service on Northwests management committee.
Compensation Committee Report
We do not have a compensation committee. 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
Donald R. Chappel
Phillip D. Wright
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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. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
As
of December 31, 2009, 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. See Part 1, Item 1. Business-General for a
description of our current ownership structure.
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 Northwests 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 Northwests 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 Northwests budget; | ||
| the approval of a transfer by a partner of its interest in Northwest; and |
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| 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 Northwests 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. 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, 2009, the advances due to Northwest by Williams totaled approximately $66.8 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 0.05 percent and zero percent at December 31, 2009 and 2008, respectively.
Northwest received interest income from advances to Williams of $74 thousand, $813 thousand and
$2,983 thousand during 2009, 2008 and 2007, respectively. In accordance with Williams
restructuring of its business, our participation in the
Williams cash management program was
terminated. In February 2010, our management committee authorized a cash distribution which
included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance
outstanding at December 31, 2009 is reflected as a reduction of our Owners
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Equity as the advances will not be available to us as working capital. As a result of
the restructuring, we will become a participant in the WPZ cash management program.
Other Related Party Transactions
Williams corporate overhead expenses allocated to Northwest were $19.7 million, $16.9 million
and $19.6 million for 2009, 2008 and 2007, 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 $16.3 million, $15.8 million and $16.6 million for 2009, 2008
and 2007, respectively. A portion of such expenses relates to the compensation of our principal
executive officer, principal financial officer and three other most highly compensated officers
(our Named Executive Officers or NEOs). Please see Item 11. Executive Compensation, for more
information about the compensation of such NEOs.
We also have transportation transactions and agreements relating to the rental of
communication facilities with subsidiaries of Williams. Combined revenues for these activities
totaled $9.9 million, $14.8 million and $11.8 million for 2009, 2008 and 2007, respectively.
From January 2008 through July 2009, we leased the Parachute Lateral facilities from an
affiliate. Under the terms of the operating lease, Northwest paid 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 $5.9 million and $10.1
million for the years ended December 31, 2009 and 2008, respectively, is included in Operation and
maintenance expense on the accompanying Consolidated Statements 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. PRINCIPAL ACCOUNTING 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:
2009 | 2008 | |||||||
(Thousands of Dollars) | ||||||||
Audit Fees |
$ | 862 | $ | 1,038 | ||||
Audit-Related Fees |
| | ||||||
Tax Fees |
| | ||||||
All Other Fees |
| | ||||||
$ | 862 | $ | 1,038 | |||||
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 2010 annual meeting of stockholders which
will be available
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upon its filing on the SECs website at http://www.sec.gov and on Williams
website at http://williams.com under the heading Investors SEC Filings.
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PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) 1. Financial Statements
Index
Page Reference to | ||||
2009 Form 10-K | ||||
Managements Annual Report on Internal Control over Financial Reporting |
41 | |||
Report of Independent Registered Public Accounting Firm |
42 | |||
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 |
43 | |||
and 2007 |
||||
Consolidated Balance Sheets at December 31, 2009 and 2008 |
44 | |||
Consolidated Statements of Owners Equity for the Years Ended December 31, 2009, |
46 | |||
2008 and 2007 |
||||
Consolidated Statements of Comprehensive Income for the Years Ended December |
47 | |||
31, 2009, 2008 and 2007 |
||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, |
48 | |||
2008 and 2007 |
||||
Notes to Consolidated Financial Statements |
49 |
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(a) 2. Financial Statement Schedules
NORTHWEST PIPELINE GP
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
Charged to | ||||||||||||||||
Beginning | Costs and | Ending | ||||||||||||||
Description | Balance | Expenses | Deductions | Balances | ||||||||||||
Year ended December 31, 2009: |
||||||||||||||||
Reserve for doubtful receivables |
$ | | $ | | $ | | $ | | ||||||||
Reserve for obsolescence of
materials and supplies |
111 | 145 | (245 | ) | 11 | |||||||||||
Year ended December 31, 2008: |
||||||||||||||||
Reserve for doubtful receivables |
7 | (7 | ) | | | |||||||||||
Reserve for obsolescence of
materials and supplies |
181 | 141 | (211 | ) | 111 | |||||||||||
Year ended December 31, 2007: |
||||||||||||||||
Reserve for doubtful receivables |
53 | (46 | ) | | 7 | |||||||||||
Reserve for obsolescence of
materials and supplies |
472 | 104 | (395 | ) | 181 |
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: |
(a) | Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference. |
(3) | Articles of incorporation and by-laws: |
(a) | Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference. | ||
(b) | Amended and Restated General Partnership Agreement of Northwest Pipeline GP (Exhibit 3.1 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008) and incorporated herein by reference. |
(4) | Instruments defining the rights of security holders, including indentures: |
(a) | Senior Indenture, dated as of November 30, 1995 between Northwest and Chemical Bank, relating to Pipelines 7.125% Debentures, due 2025 (Exhibit 4.1 to Registration Statement on Form S-3, No. 33-62639, filed September 14, 1995) and incorporated herein by reference. | ||
(b) | Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A. (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed June 23, 2006) and incorporated herein by reference. |
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(c) | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed April 6, 2007) and incorporated herein by reference. | ||
(d) | Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed as exhibit 4.1 to Northwest Pipeline GPs Form 8-K, filed May 23, 2008) and incorporated herein by reference. |
(10) | Material contracts: |
(a) | Credit Agreement, dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174) and incorporated herein by reference. | ||
(b) | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (Exhibit 10.1 to The Williams Companies, Inc. report on Form 8-K filed May 15, 2007, Commission File Number 1-4174) and incorporated herein by reference. | ||
(c) | Amendment Agreement dated November 21, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (Exhibit 10.1 to the Williams Companies, Inc., Form 8-K, filed November 28, 2007, Commission File Number 1-4174) and incorporated herein by reference. | ||
(d) | Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008) and incorporated herein by reference. | ||
(e) | Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (Exhibit 10.2 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008) and incorporated herein by reference. | ||
(f) | Registration Rights Agreement, dated as of May 22, 2008, among Northwest Pipeline GP and Banc of America Securities LLC, BNP Paribas Securities Corp., and Greenwich Capital Markets, Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed as Exhibit 10.1 to our Form 8-K, dated May 23, 2008) and incorporated herein by reference. | ||
(g) | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K, filed February 22, 2010) and incorporated herein by reference. |
(12)* | Computation of Ratio of Earnings to Fixed Charges |
(23)* | Consent of Independent Registered Public Accounting Firm | |
(24)* | Power of Attorney | |
(31) | Section 302 Certifications |
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(a)* | Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. | ||
(b)* | Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. |
(32) | Section 906 Certification |
(a)* | Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* | Filed herewith |
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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.
NORTHWEST PIPELINE GP (Registrant) |
||||
By | /s/ R. Rand Clark | |||
R. Rand Clark | ||||
Controller | ||||
Date: February 23, 2010
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.
Signature | Title | |
/s/ Phillip D. Wright*
|
Senior Vice President and Management Committee Member | |
Phillip D. Wright
|
(Principal Executive Officer) | |
/s/ Richard D. Rodekohr
|
Vice President and Treasurer
(Principal Financial Officer) |
|
/s/ Allison G. Bridges
|
Vice President | |
/s/ R. Rand Clark
|
Controller (Principal Accounting Officer) | |
R. Rand Clark |
||
/s/ Steven J. Malcolm*
|
Chief Executive Officer | |
Steven J. Malcolm |
||
/s/ Donald R. Chappel*
|
Management Committee Member | |
Donald R. Chappel |
||
* By /s/ R. Rand Clark
|
||
Attorney-in-fact |
Date: February 23, 2010
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EXHIBIT INDEX
Exhibit | Description | |||
2 | (a) | Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to Northwest
report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference. |
||
3 | (a) | Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to Northwest
report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference. |
||
3 | (b) | Amended and Restated General Partnership Agreement of Northwest Pipeline GP (Exhibit 3.1
to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008) and incorporated herein by reference. |
||
4 | (a) | Senior Indenture, dated as of November 30, 1995 between Northwest and Chemical Bank,
relating to Pipelines 7.125% Debentures, due 2025 (Exhibit 4.1 to Registration Statement on
Form S-3, No. 33-62639, filed September 14, 1995) and incorporated herein by reference. |
||
4 | (b) | Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan
Chase Bank, N.A. (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed June 23,
2006) and incorporated herein by reference. |
||
4 | (c) | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank
of New York (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed April 6, 2007) and incorporated herein by reference. |
||
4 | (d) | Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York
Trust Company, N.A., as Trustee (filed as exhibit 4.1 to Northwest Pipeline GPs Form 8-K,
filed May 23, 2008) and incorporated herein by reference. |
||
10 | (a) | Credit Agreement, dated as of May 1, 2006, among The Williams Companies, Inc., Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P.,
as Borrowers, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to The Williams
Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174) and incorporated herein by reference. |
||
10 | (b) | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams
Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation,
certain banks, financial institutions and other institutional lenders and Citibank, N.A., as
administrative agent (Exhibit 10.1 to The Williams Companies, Inc. report on Form 8-K filed
May 15, 2007, Commission File Number 1-4174) and incorporated herein by reference. |
||
10 | (c) | Amendment Agreement dated November 21, 2007, among The Williams Companies, Inc., Williams
Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain
banks, financial institutions and other institutional lenders and Citibank, N.A., as
administrative agent (Exhibit 10.1 to the Williams Companies, Inc., Form 8-K, filed November
28, 2007, Commission File Number 1-4174) and incorporated herein by reference. |
||
10 | (d) | Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP
and Northwest Pipeline Services, LLC (Exhibit 10.1 to Northwest report on Form 8-K, No.
1-7414, filed January 30, 2008) and incorporated herein by reference. |
||
10 | (e) | Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, among Williams
Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline
Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline
Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (Exhibit 10.2 to
Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008) and incorporated herein by reference. |
||
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Exhibit | Description | |||
10(f) | Registration Rights Agreement, dated as of May 22, 2008, among Northwest Pipeline GP and
Banc of America Securities LLC, BNP Paribas Securities Corp., and Greenwich Capital Markets,
Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I
thereto (filed as Exhibit 10.1 to our Form 8-K, dated May 23, 2008) and incorporated herein by reference. |
|||
10(g) | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party
thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit
10.5 to Williams Partners L.P.s Current
Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K, filed February 22, 2010) and incorporated herein by reference. |
|||
12* | Computation of Ratio of Earnings to Fixed Charges |
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23* | Consent of Independent Registered Public Accounting Firm |
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24* | Power of Attorney |
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31(a)* | Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a)
promulgated under the Securities Exchange Act of 1934, as amended and Item 601(b)(31) of
Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. |
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31(b)* | Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a)
promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of
Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. |
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32(a)* | Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* | Filed herewith |
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