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EX-31.A - EX-31.A - NORTHWEST PIPELINE LLC | c62425exv31wa.htm |
EX-31.B - EX-31.B - NORTHWEST PIPELINE LLC | c62425exv31wb.htm |
EX-32.A - EX-32.A - NORTHWEST PIPELINE LLC | c62425exv32wa.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, 2010
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 | 26-1157701 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) | |
295 Chipeta Way, Salt Lake City, Utah | 84108 | |
(Address of principal executive offices) | (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 of this chapter) 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 | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
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
The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K
and is therefore filing this Form 10-K with the reduced disclosure format.
NORTHWEST PIPELINE GP
FORM 10-K
FORM 10-K
TABLE OF CONTENTS
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DEFINITIONS
We use the following gas measurements in this report:
Mcf-means thousand cubic feet.
MMcf-means million cubic feet.
Bcf-means billion cubic feet.
MMBtu-means million British Thermal Units.
TBtu-means trillion British Thermal Units.
Dth-means dekatherm.
Mdth-means thousand dekatherms.
MMdth-means million dekatherms.
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PART I
Item 1. | BUSINESS |
In this report, Northwest is at times referred to in the first person as we, us or our.
At December 31, 2010, Northwest is owned by Williams Partners L.P. (WPZ), a publicly traded
Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and
Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent
limited partner interest and all of WPZs 2 percent general partner interest.
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).
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 477,000 horsepower. At December 31, 2010, we had long-term firm
transportation contracts, including peaking service, with aggregate capacity reservations of
approximately 3.8 Bcf of natural gas per day.
We own a one-third interest in the Jackson Prairie underground storage facility located near
Chehalis, Washington. 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 also have storage capacity in a Liquefied Natural Gas (LNG) facility near
Plymouth, Washington, that we own and operate. We have approximately 13.2 Bcf of working natural
gas storage capacity through these three storage facilities, which is substantially utilized for
third-party natural gas. These natural gas storage facilities enable us to balance daily receipts
and deliveries and provide storage services to certain major customers.
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 2010, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas
Company, which accounted for approximately 22.7 percent and 11.4 percent, respectively, of our
total operating revenues for the year ended December 31, 2010. 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.
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CAPITAL PROJECTS
Sundance Trail Expansion
On November 1, 2010, we placed the Sundance Trail Expansion Project in service which is
comprised of approximately 16 miles of 30-inch loop between our existing Green River and Muddy
Creek compressor stations in Wyoming as well as an upgrade to our existing Vernal compressor
station. The total project is estimated to cost approximately $50 million, including the cost of
replacing the existing compression at Vernal, which will enhance the efficiency of our system. We
executed a transportation service 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 will collect our maximum system rates under the firm service agreement, and have received
approval from the FERC to roll-in the Sundance Trail Expansion costs in any future rate cases.
REGULATION
Our interstate transmission and storage activities are subject to regulation by the FERC under
the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978 (NGPA),
as amended, and, as such, our rates and charges for the transportation of natural gas in interstate
commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting,
among other things, are subject to regulation. We hold certificates of public convenience and
necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and
properties under the NGA. The FERCs Standards of Conduct govern the relationship between natural
gas transmission providers and 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 gas marketing employees and by
restricting the information that transmission providers may provide to gas marketing employees.
Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1
million per day for each violation of its rules.
Our transportation rates are established through the FERC ratemaking process. Key
determinants in the ratemaking process are (1) costs of providing service, including depreciation
expense, (2) allowed rate of return, including the equity component of the capital structure and
related income taxes, and (3) contract volume and throughput assumptions. The allowed rate of
return is determined in each rate case. Rate design and the allocation of costs between the
reservation and commodity rates also impact profitability. As a result of these proceedings,
certain revenues may be collected subject to refund. We record estimates of rate refund
liabilities considering our and third-party regulatory proceedings, advice of counsel and other
risks.
Safety and Maintenance
Pipeline Integrity Regulations We are also subject to the Natural Gas Pipeline Safety Act of
1968, as amended by Title I of the Pipeline Safety Act of 1979, and the Pipeline Safety Improvement
Act of 2002 which regulate safety requirements in the design, construction, operation and
maintenance of interstate gas transmission facilities.
We have developed an Integrity Management Program 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. The rule
requires gas pipeline operators to develop an integrity management program for transmission
pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity
Management Program includes a baseline assessment plan along with periodic reassessments to be
completed within required timeframes. In meeting the integrity regulations, we have identified
high consequence areas and developed our baseline assessment plan. We are on schedule to complete
the required baseline assessments within the required timeframes. Currently, we estimate that the
cost to complete the required initial assessments over the period of 2011 through 2012 and
associated remediation will be primarily
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capital in nature and range between $50 million and $60 million. Ongoing periodic
reassessments and initial assessments of any new high consequence areas will be completed within
the timeframes required by the rule. 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.
Environmental Regulation
We are subject to the National Environmental Policy Act and federal, state and local laws and
regulations relating to environmental quality control. Management believes that, capital
expenditures and operation and maintenance expenses required to meet applicable environmental
standards and regulations are generally recoverable in rates. For these reasons, management
believes that compliance with applicable environmental requirements is not likely to have a
material effect upon our competitive position or earnings. Please see Item 8. Financial
Statements and Supplementary Data Notes to Financial Statements: Note 2. Contingent Liabilities
and Commitments Environmental Matters.
EMPLOYEES
Northwest has no employees. Operations, management, and certain administrative services are
provided to Northwest by Northwest Pipeline Services LLC, a Williams affiliate. As of January 31,
2011, Northwest Pipeline Services LLC had 448 employees.
TRANSACTIONS WITH AFFILIATES
We engage in transactions with WPZ, Williams and other Williams subsidiaries. Please see
Item 8. Financial Statements and Supplementary Data Notes to Financial Statements: Note 1.
Summary of Significant Accounting Policies and Note 7. Transactions with Major Customers.
Item 1A. | RISK FACTORS |
FORWARD-LOOKING
STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE
SAFE HARBOR PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
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 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; |
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| Cash flow from operations or results of operations; | ||
| 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 climate change legislation), environmental liabilities, litigation, and rate proceedings; | ||
| Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates; | ||
| Changes in maintenance and construction costs; | ||
| Changes in the current geopolitical situation; | ||
| Our exposure to the credit risks 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 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 level of damages resulting from these
risks. In spite of our 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
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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 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 are having the effect of increasing the
natural gas transportation and storage options for our traditional customer base. Similarly, a
highly-liquid competitive commodity market in natural gas and increasingly competitive markets for
natural gas services, including competitive secondary markets in pipeline capacity, have developed.
As a result, pipeline capacity is being used more efficiently, and peaking and storage services
are increasingly effective substitutes for annual pipeline capacity. 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 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. All of these
competitive pressures could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
Certain of our services are subject to long-term, discounted or negotiated rate contracts where the
revenues received from such contracts may be less than the cost to perform such services.
We provide some services pursuant to long-term, discounted or negotiated rate contracts. It
is possible that costs to perform services under such contracts will exceed the revenues we collect
for our services. Although most of the services are priced at cost-based rates that are subject to
adjustment in rate cases, under FERC policy, a regulated service provider and a customer may
mutually agree to sign a contract for service at a discount or negotiated rate that may be above
or below FERC regulated cost-based rate for that service.
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. Upon expiration of the terms, we may
not be able to extend contracts with existing customers or 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 |
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| the effects of state regulation on customer contracting practices. |
Any failure to extend or replace a significant portion of our existing contracts may have a
material adverse effect on our business, financial condition, results of operations and cash flows.
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, 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 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 transportation, and import and export of natural gas supplies, adversely impacting our
ability to fill the capacities of our transportation 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. In addition, if natural gas prices in the supply basins
connected to our pipeline systems are higher than prices in other natural gas producing regions,
our ability to compete with other transporters may be negatively impacted on a short-term basis, as
well as with respect to our long-term recontracting activities.
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, if development
in new supply basins where we do not have significant pipeline systems reduces demand for our
services, 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
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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
reduction in or termination of our long-term transportation and storage contracts or throughput on
our system.
Higher natural gas prices over the long term could result in a decline in the demand for
natural gas and, therefore, in our long-term transportation and storage contracts or throughput on
our system. Also, lower natural gas prices over the long term could result in a decline in the
production of natural gas resulting in reduced contracts or throughput on our system. As a result,
significant prolonged changes in natural gas prices could have a material adverse effect on our
business, financial condition, results of operations, and cash flows.
Our costs of maintaining or repairing our facilities may exceed our expectations and the FERC or
competition in our markets may not allow us to recover such costs in the rates we charge for our
services.
We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by
regulatory authorities to undertake modifications to our systems that could result in a material
adverse impact on our business, financial condition and results of operations if the costs of
maintaining or repairing our facilities exceed current expectations and the FERC or competition in
our markets do not allow us to recover such costs in the rates we charge for our service.
Our business is subject to complex government regulations. The operation of our business might be
adversely affected by changes in these regulations or in their interpretation or implementation, or
the introduction of new laws or regulations applicable to our business or our customers.
Existing regulations might be revised or reinterpreted, new laws and regulations might be
adopted or become applicable to us, our facilities or our customers, and future changes in laws and
regulations could have a material adverse effect on our financial condition and results of
operations. For example, several ruptures on third party pipelines have occurred recently. In
response, various legislative and regulatory reforms associated with pipeline safety and integrity
have been proposed, including reforms that would require increased periodic inspections,
installation of additional valves and other equipment operated by us and subjecting additional
pipelines (including gathering facilities) to more stringent regulation. Such reforms, if adopted,
could significantly increase our costs.
We are subject to risks associated with climate change.
There is a belief that emissions of greenhouse gases (GHGs) may be linked to climate change.
Climate change and the costs that may be associated with its impacts and the regulation of GHGs
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, 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. These laws include:
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| Clean Air Act (CAA), and analogous state laws, which impose obligations related to air emissions; | ||
| Clean Water Act (CWA), and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters; | ||
| Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and | ||
| Resource Conservation and Recovery Act (RCRA), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities. |
Various governmental authorities, including the U.S. Environmental Protection Agency (EPA) and
analogous state agencies and the U.S. 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 the incurrence of environmental costs and liabilities in our
business, some of which may be material, due to our handling of the products we transport and
store, air emissions related to our operations, historical industry operations, waste disposal
practices, and the prior use of flow meters containing mercury. 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, for the remediation of contaminated areas 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. Some sites we operate are located near current or former third-party hydrocarbon
storage and processing operations, and there is a risk that contamination has migrated from those
sites to ours. 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 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 are also generally responsible for all liabilities associated with
the environmental condition of our facilities and assets, whether acquired or developed, regardless
of when the liabilities arose and whether they are known or unknown.
In addition, Legislative and regulatory responses related to GHGs and climate change create
the potential for financial risk. The U.S. 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, regional, and/or federal
requirements to reduce or mitigate GHG emissions.
Numerous states have 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 lead to the direct regulation of GHG emissions in our
industry under the EPAs interpretation of its authority and obligations under the CAA. The recent
actions
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of the EPA and the passage of any federal or state climate change laws or regulations 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.
Certain environmental and other groups have suggested that additional laws and regulations may
be needed to more closely regulate the hydraulic fracturing process commonly used in natural gas
production. Legislation to further regulate hydraulic fracturing has been proposed in Congress and
the U.S. Department of Interior has announced plans to formalize obligations for disclosure of
chemicals associated with hydraulic fracturing on federal lands. In addition, some state and local
authorities have considered or formalized new rules related to hydraulic fracturing and enacted
moratoria on such activities. We cannot predict whether any additional federal, state or local
legislation or regulation will be enacted in this area and if so, what its provisions would be. If
additional levels of reporting, regulation and permitting were required, natural gas supplies and
prices could be impacted and our operations could be adversely affected.
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 affect
our profitability.
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. Although
some of these customers are subject to long-term contracts, we may be unable to negotiate extension
or replacements of these contracts on favorable terms, if at all. For the year ended December 31,
2010, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company.
These customers accounted for approximately 34.1 percent of our operating revenues for the year
ended December 31, 2010. The loss of all, or even a portion of, the revenues from contracted
volumes supplied by these customers, 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, results of operations, financial condition, and cash flows, unless we are
able to acquire comparable volumes 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.
The failure of counterparties to perform their contractual obligations could adversely affect our
operating results and financial condition.
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Despite performing credit analysis prior to extending credit, we are exposed to the credit
risk of our contractual counterparties in the ordinary course of business even though we monitor
these situations and attempt to take appropriate measures to protect ourselves. In addition to
credit risk, counterparties to our commercial agreements, such as transportation and storage
agreements, may fail to perform their other contractual obligations. A failure of counterparties
to perform their contractual obligations could cause us to write down or write off doubtful
accounts, which could materially adversely affect our operating results and financial condition.
If third-party pipelines and other facilities interconnected to our pipeline and facilities become
unavailable to transport natural gas, our revenues could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and
from our pipeline and storage facilities for the benefit of our customers. 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. 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. In those
instances in which we do not own the land on which our facilities are located, we obtain 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 may 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, results
of operations, financial condition and cash flows.
We do not insure against all potential losses and could be seriously harmed by unexpected
liabilities or by the inability of our insurers to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental
accidents. We do not maintain insurance in the type and amount to cover all possible risks of
loss.
We currently maintain excess liability insurance with limits of $610 million per occurrence
and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us
and certain of our affiliates for legal and contractual liabilities arising out of bodily 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.
Although we maintain property insurance on property we own, lease, or are responsible to
insure, the policy may not cover the full replacement cost of all damaged assets or the entire
amount of business interruption loss we may experience. In addition, certain perils may be
excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the
type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks.
We do not insure our onshore underground pipelines for physical damage, except at certain
locations such as river crossings and compressor stations. All of our 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.
In addition, any insurance company that provides coverage to us may experience negative
developments that could impair their ability to pay any of our claims. As a result, we could be
exposed to
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greater losses than anticipated and may have to obtain replacement insurance, if available, at
a greater cost.
The occurrence of any risks not fully covered by insurance could have a material adverse
effect on our business, financial condition, results of operations and cash flows, and our ability
to repay our debt.
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.
Our growth may be dependent upon the construction of new transportation and storage facilities
as well as the expansion of existing facilities. Construction or expansion 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 | ||
| 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 our 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, and companies relationships with their independent public accounting firms. It
remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate
impact that any such new laws or regulations could have. In addition, the Financial Accounting
Standards Board (FASB), the SEC or FERC could enact new accounting standards or FERC orders that
might impact how we are required to record revenues, expenses, assets, and liabilities. Any
significant change in accounting standards or disclosure requirements could have a material adverse
effect on our business, results of operations, and financial condition.
We do not operate all of our assets. This reliance on others to operate our assets and to provide
other services could adversely affect our business and operating results.
Williams and other third parties operate certain of our assets. We have a limited ability to
control these operations and the associated costs. The success of these operations is therefore
dependent upon a number of factors that are outside our control, including the competence and
financial resources of the operators.
We rely on Williams for certain services necessary for us to be able to conduct our
business. Williams may outsource some or all of these services to third parties, and a failure of
all or part of
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Williams relationships with its outsourcing providers could lead to delays in or
interruptions of these services. Our reliance on Williams and others as operators and on Williams
outsourcing relationships, and our limited ability to control certain costs could have a material
adverse effect on our business, results of operations, and financial condition.
Risks Related to Strategy and Financing
Restrictions in our debt agreements and our leverage may affect our future financial and operating
flexibility.
Our total outstanding long-term debt as of December 31, 2010, was $693.6 million.
Our debt service obligations and restrictive covenants in our new credit facility entered into
as part of Williams restructuring (New Credit Facility) and the indentures governing our senior
unsecured notes could have important consequences. For example, they could:
| Make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes; | ||
| Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other purposes; | ||
| Diminish our ability to withstand a continued or future downturn in our business or the economy generally; | ||
| Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes; | ||
| Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and | ||
| Place us at a competitive disadvantage compared to our competitors that have proportionately less debt. |
Our ability to repay, extend or refinance our existing debt obligations and to obtain future
credit will depend primarily on our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory, business and other factors, many of
which are beyond our control. Our ability to refinance existing debt obligations or obtain future
credit will also depend upon the current conditions in the credit markets and the availability of
credit generally. If we are unable to meet our debt service obligations, we could be forced to
restructure or refinance our indebtedness, seek additional equity capital, or sell assets. We may
be unable to obtain financing or sell assets on satisfactory terms, or at all.
We are not prohibited under our indentures from incurring additional indebtedness. Our
incurrence of significant additional indebtedness would exacerbate the negative consequences
mentioned above, and could adversely affect our ability to repay our senior notes.
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 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
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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 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. 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. 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 WPZ credit rating would likely also
result in a downgrading of our credit rating. A downgrading of a Williams or WPZ 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, WPZ, or Williams to provide additional collateral to third parties.
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A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of
doing business, and independent third parties determine our credit ratings outside of our control.
A downgrade of our credit rating might increase our cost of borrowing and could cause us to
post collateral with third parties, 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. 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 we will maintain our current credit ratings.
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, 2010, we are a wholly-owned subsidiary of WPZ, approximately 75 percent of
whose limited and general partnership interests are owned by Williams. 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. |
WPZ 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; |
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| 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 affiliated companies who are involved in marketing functions of the natural gas business; and | ||
| market manipulation in connection with interstate sales, purchases, or transportation of natural gas. |
Under the Natural Gas Act (NGA), FERC has authority to regulate interstate providers of
natural gas pipeline transportation and storage services in interstate commerce, and such providers
may only charge rates that have been determined to be just and reasonable by FERC. In addition,
FERC prohibits providers from unduly preferring or unreasonably discriminating against any person
with respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas can affect our business in many ways, including decreasing
tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise
altering the profitability of our business.
The 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 FERC in our future rate cases will be inadequate to recover
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.
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Legal and regulatory proceedings and investigations relating to the energy industry have adversely
affected our business and may continue to do so.
Public and regulatory scrutiny of the energy industry has resulted in increased regulation
being either proposed or implemented. Such scrutiny has also resulted in various inquiries,
investigations and court proceedings. 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. Adverse effects may
continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional
inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In
addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will
lead to additional legal proceedings against us, civil or criminal fines or penalties, or other
regulatory action, including legislation, which might be materially adverse to the operation of our
business and our revenues and net income or increase our operating costs in other ways. Current
legal proceedings or other matters against us including environmental matters, 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, Williams may not be able to replace them with
employees of comparable knowledge and experience. In addition, Williams may not be able to retain
or recruit other qualified individuals, and Williams 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 pension 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
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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 has not been available at all. A
significant disruption in operations or a significant liability for which we were not fully insured
could have a material adverse effect on our business, results of operations, and financial
condition.
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
Our gas pipeline facilities are generally owned in fee. However, a substantial portion of
such facilities 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
company 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 Financial Statements: Note 2. Contingent Liabilities and
Commitments Legal Proceedings.
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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, 2010, we were owned 100 percent by WPZ, a publicly traded master limited
partnership, and Williams held an approximate 75 percent interest in WPZ. Our partnership interest
is not publicly traded.
We paid $191.5 million and $135.0 million in cash distributions to our partners during 2010
and 2009, respectively.
Item 6. SELECTED FINANCIAL DATA
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K,
this information is omitted.
Item 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
The following discussion and analysis of critical accounting estimates, results of operations,
and capital resources and liquidity should be read in conjunction with the financial statements and
notes thereto included within Part II, Item 8 of this report.
CRITICAL ACCOUNTING ESTIMATES
Our financial statements reflect the selection and application of accounting policies that
require management to make significant estimates and assumptions. We believe that the following
are the most critical judgment areas in the application of accounting policies that currently
affect our financial condition and results of operations.
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
financial statements include the effects of the types of transactions described above that result
from regulatory accounting requirements. Managements assessment of the probability of recovery or
pass through of regulatory assets and liabilities requires judgment and interpretation of laws and
regulatory commission orders. If, for any reason, we cease to meet the criteria for application of
regulatory accounting treatment for all or part of our operations, the regulatory assets and
liabilities related to those portions ceasing to meet such criteria would be eliminated from the
Balance Sheet and included in the Statement of Income for the period in which the discontinuance of
regulatory accounting treatment occurs.
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The aggregate amounts of regulatory assets reflected in
the Balance Sheet are $62.4 million and $59.3
million at December 31, 2010 and 2009, respectively. The aggregate amounts of regulatory
liabilities reflected in the Balance Sheet are $17.0 million and $15.5 million at December 31, 2010
and 2009, respectively. A summary of regulatory assets and liabilities is included in Note 9 of
Notes to Financial Statements.
Contingent Liabilities
We record liabilities for estimated loss contingencies when we assess that a loss is probable
and the amount of the loss can be reasonably estimated. At December 31, 2010 and 2009, we have an
accrual for loss contingencies of $0 and $800 thousand, respectively. Revisions to contingent
liabilities are generally reflected in income when new or 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 our assumptions and estimates
pertaining to probability and amount of loss, and incorporate the advice of legal counsel,
engineers or other third parties regarding the probable outcomes of the matter. As new
developments occur or more information becomes available, our assumptions and estimates of these
liabilities may change. If changes in these or other assumptions or the anticipated outcomes we
use to estimate contingencies cause a loss to become more likely, it could materially affect future
results of operations for any particular quarterly or annual period, but would not be expected to
have a material adverse effect on our future liquidity or financial position.
RESULTS OF OPERATIONS
Analysis of Financial Results
This analysis discusses financial results of our operations for the years 2010 and 2009.
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.
2010 Compared to 2009
Our operating revenues decreased $12.6 million, or 3 percent, for the year ended December 31,
2010 as compared to the year ended December 31, 2009. This decrease is primarily attributed to i)
a reduction in lease revenues of $6.1 million resulting from the termination of the Parachute
Lateral lease on August 1, 2009, ii) lower other revenues of $3.3 million resulting from the
absence of sublease income attributed to the restructuring of the Salt Lake City headquarters
building lease, iii) lower firm transportation commodity revenues of $3.0 million due primarily to
mild weather in our market area and lower off-system deliveries, iv) lower revenues of $2.7 million
resulting from the termination of the Everett Delta Lateral lease on November 9, 2009, and v) lower
storage revenue of $1.2 million due primarily to less capacity released at Clay Basin in 2010.
These decreases are partially offset by higher reservation charges due primarily to the completion
of the Sundance Trail Expansion Project. The revenue decreases from the Parachute and Everett
Delta laterals as well as the reduction in building sublease revenues are substantially offset by
decreases in lease expenses as described below.
Our transportation service accounted for 97 percent and 96 percent of our operating revenues
for the years ended December 31, 2010 and 2009, respectively. Additionally, gas storage service
accounted for 3 percent and 4 percent of operating revenues for the years ended December 31, 2010
and 2009, respectively.
Total operating expenses decreased $6.8 million, or 3 percent. This decrease is due primarily
to i) the termination of the Parachute and Everett Delta leases, resulting in lower lease expense
of $8.6 million, ii) the restructuring of the Salt Lake City headquarters building lease in 2009
resulting in lower building lease expense of $3.6 million, iii) lower incentive compensation
expense of $1.5 million, and iv) lower pension expense of $1.4 million. These decreases were
partially offset by i) higher property taxes of $3.6 million primarily attributed to a $2.6 million
reduction in 2009 for lower than anticipated mill levies and property additions, ii) higher labor
of $1.7 million and higher contractual expenses of $1.7 million attributed to higher maintenance,
and iii) higher depreciation expense of $1.5 million due to property additions.
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Other income net decreased $0.9 million, or 47 percent, due primarily to 2010 expenses of
$1.3 million attributed to business development.
Interest charges decreased $2.6 million, or 5 percent, due primarily to the completion of the
amortization of debt expense associated with a retired debt issue.
Effects of Inflation
We generally have experienced increased costs due to the effect of inflation on the cost of
labor, materials and supplies, and property, plant, and equipment. A portion of the increased
labor and materials and supplies cost can directly affect income through increased operation and
maintenance expenses. The cumulative impact of inflation over a number of years has resulted in
increased costs for current replacement of productive facilities. The majority of our property,
plant, and equipment and materials and supplies inventory is subject to ratemaking treatment, and
under current FERC practices, recovery is limited to historical costs. We believe that we will be
allowed to recover and earn a return based on increased actual costs incurred when existing
facilities are replaced. Cost-based regulation along with competition and other market factors
limit our ability to price services or products based upon inflations effect on costs.
CAPITAL RESOURCES AND LIQUIDITY
METHOD OF FINANCING
We fund our working capital and capital requirements with cash flows from operating
activities, equity contributions from WPZ, collection of advances made to WPZ, accessing capital
markets, and, if required, borrowings under the New Credit Facility (described below) and advances
from WPZ.
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 public and private debt markets on terms commensurate with our credit
ratings to finance our capital requirements, when needed.
Through January 31, 2010, we were a participant in Williams cash management program and made
advances to and received advances from Williams. As a result of the restructuring, we became a
participant in WPZs cash management program. At December 31, 2010, the advances due to us by WPZ
totaled $45.0 million. The advances are represented by demand notes. The interest rate on the WPZ
demand notes is based upon the overnight investment rate paid on WPZs excess cash, which was
approximately 0.06 percent at December 31, 2010.
Prior to Williams restructuring of its business, we participated in Williams unsecured $1.5
billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. 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, under certain conditions,
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 December 31, 2010, the
full $400 million under the New Credit Facility was available. Please see Item 8. Financial
Statements and Supplementary Data Notes to Financial Statements: Note 3. Debt, Financing
Arrangements, and Leases Revolving Credit and Letter of Credit Facility.
CAPITAL EXPENDITURES
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
21
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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 2011 capital expenditures will be between $115 million
and $135 million. Of this total, $60 million to $70 million is considered nondiscretionary due to
legal, regulatory, and/or contractual requirements. In 2011, we expect to fund our capital
expenditures with cash from operations.
Property, plant, and equipment additions were $120.2 million, $152.6 million and $88.5 million
for 2010, 2009 and 2008, respectively. The $64.1 million increase from 2008 to 2009 is primarily
attributed to expenditures related to pipeline integrity, the Colorado Hub Connection Project, and
the Sundance Trail Expansion Project.
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, 2010 | ||||
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 |
(1,366 | ) | ||
Total long-term debt |
$ | 693,634 | ||
Our total long-term debt at December 31, 2010 had a carrying value of $693.6 million and a
fair market value of $796.1 million. As of December 31, 2010, the weighted-average interest rate on
our long-term debt was 6.4 percent.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
23
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MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
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 (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, 2010, based on the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control
Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2010, our
internal control over financial reporting was effective.
This annual report does not include a report of our registered public accounting firm
regarding internal control over financial reporting. A report by our registered public accounting
firm is not required pursuant to rules of the Securities and Exchange Commission that permit us 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 balance sheets of Northwest Pipeline GP as of December 31,
2010 and 2009, and the related statements of income, comprehensive income, owners equity, and cash
flows for each of the three years in the period ended December 31, 2010. 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 financial position of Northwest Pipeline GP at December 31, 2010 and 2009, and the
results of its operations and its cash flows for each of the three years in the period ended
December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects the information set
forth therein.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2011
February 24, 2011
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NORTHWEST PIPELINE GP
STATEMENT OF INCOME
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
OPERATING REVENUES |
$ | 421,817 | $ | 434,379 | $ | 434,854 | ||||||
OPERATING EXPENSES: |
||||||||||||
General and administrative |
57,162 | 64,657 | 60,403 | |||||||||
Operation and maintenance |
65,516 | 71,085 | 72,831 | |||||||||
Depreciation |
87,915 | 86,373 | 86,184 | |||||||||
Regulatory credits |
(1,662 | ) | (2,403 | ) | (2,617 | ) | ||||||
Taxes, other than income taxes |
18,106 | 14,158 | 16,875 | |||||||||
Total operating expenses |
227,037 | 233,870 | 233,676 | |||||||||
Operating income |
194,780 | 200,509 | 201,178 | |||||||||
OTHER INCOME net: |
||||||||||||
Interest income |
||||||||||||
Affiliated |
27 | 74 | 813 | |||||||||
Other |
3 | 16 | 6 | |||||||||
Allowance for equity funds used during construction |
1,947 | 1,996 | 812 | |||||||||
Miscellaneous other expense, net |
(942 | ) | (135 | ) | (8 | ) | ||||||
Total other income net |
1,035 | 1,951 | 1,623 | |||||||||
INTEREST CHARGES: |
||||||||||||
Interest on long-term debt |
44,458 | 44,439 | 42,290 | |||||||||
Other interest |
2,664 | 5,414 | 5,571 | |||||||||
Allowance
for borrowed funds used during construction |
(877 | ) | (1,044 | ) | (431 | ) | ||||||
Total interest charges |
46,245 | 48,809 | 47,430 | |||||||||
INCOME BEFORE INCOME TAXES |
149,570 | 153,651 | 155,371 | |||||||||
INCOME TAXES (Note 5) |
43 | | | |||||||||
NET INCOME |
$ | 149,527 | $ | 153,651 | $ | 155,371 | ||||||
See accompanying notes.
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NORTHWEST PIPELINE GP
BALANCE SHEET
(Thousands of Dollars)
December 31, | ||||||||
2010 | 2009 | |||||||
(Restated) | ||||||||
ASSETS |
||||||||
CURRENT ASSETS: |
||||||||
Cash and cash equivalents |
$ | 5 | $ | 402 | ||||
Advances to affiliate |
45,045 | | ||||||
Accounts receivable |
||||||||
Trade |
38,515 | 40,442 | ||||||
Affiliated companies |
2,118 | 4,514 | ||||||
Materials and supplies, less reserves of $613 for 2010 and $11
for 2009 |
11,719 | 9,960 | ||||||
Exchange gas due from others |
2,323 | 4,089 | ||||||
Exchange gas offset |
3,854 | 10,288 | ||||||
Prepayments and other |
3,415 | 4,241 | ||||||
Total current assets |
106,994 | 73,936 | ||||||
PROPERTY, PLANT AND EQUIPMENT, at cost |
2,965,097 | 2,887,021 | ||||||
Less Accumulated depreciation |
1,017,634 | 950,708 | ||||||
Total property, plant and equipment, net |
1,947,463 | 1,936,313 | ||||||
OTHER ASSETS: |
||||||||
Deferred charges |
11,817 | 13,996 | ||||||
Regulatory assets |
60,176 | 57,032 | ||||||
Total other assets |
71,993 | 71,028 | ||||||
Total assets |
$ | 2,126,450 | $ | 2,081,277 | ||||
See accompanying notes.
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NORTHWEST PIPELINE GP
BALANCE SHEET
(Thousands of Dollars)
December 31, | ||||||||
2010 | 2009 | |||||||
(Restated) | ||||||||
LIABILITIES AND OWNERS EQUITY |
||||||||
CURRENT LIABILITIES: |
||||||||
Accounts payable |
||||||||
Trade |
$ | 13,177 | $ | 17,552 | ||||
Affiliated companies |
10,105 | 23,131 | ||||||
Accrued liabilities |
||||||||
Taxes, other than income taxes |
10,186 | 8,176 | ||||||
Interest |
4,045 | 4,045 | ||||||
Exchange gas due to others |
13,115 | 14,377 | ||||||
Other |
4,245 | 5,270 | ||||||
Total current liabilities |
54,873 | 72,551 | ||||||
LONG-TERM DEBT |
693,634 | 693,437 | ||||||
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES |
88,347 | 108,139 | ||||||
CONTINGENT LIABILITIES AND COMMITMENTS |
||||||||
OWNERS EQUITY: |
||||||||
Owners capital |
1,046,862 | 1,027,862 | ||||||
Loan to affiliate |
| (105,431 | ) | |||||
Retained earnings |
242,396 | 284,319 | ||||||
Accumulated other comprehensive income |
338 | 400 | ||||||
Total owners equity |
1,289,596 | 1,207,150 | ||||||
Total liabilities and owners equity |
$ | 2,126,450 | $ | 2,081,277 | ||||
See accompanying notes. |
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NORTHWEST PIPELINE GP
STATEMENT OF OWNERS EQUITY
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Owners capital |
||||||||||||
Balance at beginning of period |
$ | 1,027,862 | $ | 978,682 | $ | 977,022 | ||||||
Capital contribution from Williams |
19,000 | 49,180 | 1,660 | |||||||||
Balance at end of period |
1,046,862 | 1,027,862 | 978,682 | |||||||||
Loans (to) from affiliate |
||||||||||||
Balance at beginning of period |
(105,431 | ) | (34,265 | ) | (29,186 | ) | ||||||
Loans (to) from affiliate |
105,431 | (71,166 | ) | (5,079 | ) | |||||||
Balance at end of period |
| (105,431 | ) | (34,265 | ) | |||||||
Retained earnings |
||||||||||||
Balance at beginning of period |
284,319 | 265,668 | 228,739 | |||||||||
Net income |
149,527 | 153,651 | 155,371 | |||||||||
Cash distributions |
(191,450 | ) | (135,000 | ) | (419,342 | ) | ||||||
Sale of partnership interest |
| | 300,900 | |||||||||
Balance at end of period |
242,396 | 284,319 | 265,668 | |||||||||
Accumulated other comprehensive income (loss) |
||||||||||||
Balance at beginning of period |
400 | 462 | 523 | |||||||||
Cash flow hedges: |
||||||||||||
Reclassification of gain into earnings |
(62 | ) | (62 | ) | (61 | ) | ||||||
Balance at end of period |
338 | 400 | 462 | |||||||||
Total owners equity |
$ | 1,289,596 | $ | 1,207,150 | $ | 1,210,547 | ||||||
See accompanying notes.
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NORTHWEST PIPELINE GP
STATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Net Income |
$ | 149,527 | $ | 153,651 | $ | 155,371 | ||||||
Cash Flow Hedges: |
||||||||||||
Amortization of cash flow hedges |
(62 | ) | (62 | ) | (61 | ) | ||||||
Total comprehensive income |
$ | 149,465 | $ | 153,589 | $ | 155,310 | ||||||
See accompanying notes.
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NORTHWEST PIPELINE GP
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Thousands of Dollars)
Years Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(Restated) | (Restated) | |||||||||||
OPERATING ACTIVITIES: |
||||||||||||
Net Income |
$ | 149,527 | $ | 153,651 | $ | 155,371 | ||||||
Adjustments
to reconcile to net cash provided by operating activities |
||||||||||||
Depreciation |
87,915 | 86,373 | 86,184 | |||||||||
Regulatory credits |
(1,662 | ) | (2,403 | ) | (2,617 | ) | ||||||
Gain on sale of property, plant and equipment |
| (508 | ) | (378 | ) | |||||||
Amortization of deferred charges and credits |
2,293 | 5,050 | 5,132 | |||||||||
Allowance for equity funds used during construction |
(1,947 | ) | (1,996 | ) | (812 | ) | ||||||
Reserve for doubtful accounts |
| | (7 | ) | ||||||||
Cash
provided (used) by changes in current assets and liabilities: |
||||||||||||
Trade accounts receivable |
1,927 | (326 | ) | 580 | ||||||||
Affiliated receivables, including income taxes |
2,396 | (3,284 | ) | 2,284 | ||||||||
Exchange gas due from others |
1,262 | 2,623 | (252 | ) | ||||||||
Materials and supplies |
(1,759 | ) | (143 | ) | 527 | |||||||
Other current assets |
826 | 1,744 | 943 | |||||||||
Trade accounts payable |
(559 | ) | (828 | ) | (2,599 | ) | ||||||
Affiliated payables, including income taxes |
(13,026 | ) | 350 | (12,084 | ) | |||||||
Exchange gas due to others |
(1,262 | ) | (2,623 | ) | 252 | |||||||
Other accrued liabilities |
985 | (4,860 | ) | 4,487 | ||||||||
Changes in noncurrent assets and liabilities: |
||||||||||||
Deferred charges |
(5,865 | ) | (3,362 | ) | (4,747 | ) | ||||||
Other deferred credits |
8,148 | 5,340 | 6,750 | |||||||||
Net cash provided by operating activities |
229,199 | 234,798 | 239,014 | |||||||||
FINANCING ACTIVITIES: |
||||||||||||
Proceeds from issuance of long-term debt |
8,000 | | 249,333 | |||||||||
Retirement of long-term debt |
(8,000 | ) | | (250,000 | ) | |||||||
Debt issuance costs |
| | (2,027 | ) | ||||||||
Capital contribution from parent |
19,000 | 49,180 | 1,660 | |||||||||
Proceeds from sale of partnership interest |
| | 300,900 | |||||||||
Distributions paid |
(191,450 | ) | (135,000 | ) | (419,342 | ) | ||||||
Changes in cash overdrafts |
(1,209 | ) | 2,212 | (7,372 | ) | |||||||
Net cash used in financing activities |
(173,659 | ) | (83,608 | ) | (126,848 | ) | ||||||
INVESTING ACTIVITIES: |
||||||||||||
Property, plant and equipment |
||||||||||||
Capital expenditures* |
(120,236 | ) | (152,580 | ) | (88,478 | ) | ||||||
Proceeds from sales |
3,913 | 2,234 | 3,065 | |||||||||
Repayments from (advances to) affiliates |
60,386 | (787 | ) | (26,905 | ) | |||||||
Net cash used in investing activities |
(55,937 | ) | (151,133 | ) | (112,318 | ) | ||||||
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS |
(397 | ) | 57 | (152 | ) | |||||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
402 | 345 | 497 | |||||||||
CASH AND CASH EQUIVALENTS AT END OF YEAR |
$ | 5 | $ | 402 | $ | 345 | ||||||
______________________ |
||||||||||||
* Increases to property, plant and equipment |
$ | (117,629 | ) | $ | (156,576 | ) | $ | (78,566 | ) | |||
Changes in related accounts payable and accrued liabilities |
(2,607 | ) | 3,996 | (9,912 | ) | |||||||
Capital expenditures |
$ | (120,236 | ) | $ | (152,580 | ) | $ | (88,478 | ) | |||
Supplemental disclosures of non-cash transactions: |
||||||||||||
Adjustment to owners equity for benefit plans correction |
$ | | $ | (4,402 | ) | $ | (5,079 | ) | ||||
Loans to affiliate reclassified to equity |
| 66,764 | |
See accompanying notes.
31
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NORTHWEST PIPELINE GP
NOTES TO 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.
At December 31, 2010, Northwest is owned by Williams Partners L.P. (WPZ), a publicly traded
Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and
Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent
limited partner interest and all of WPZs 2 percent general partner interest.
Northwest is not an employer. Services are provided to Northwest by Northwest Pipeline
Services LLC (NPS), a Williams affiliate. Northwest reimburses NPS for the costs of the employees
including compensation and employee benefit plan costs and all related administrative costs.
In this report, Northwest is at times referred to in the first person as we, us or our.
Nature of Operations
We own and operate an interstate pipeline system for the mainline transmission of natural gas.
This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado
through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border
near Sumas, Washington.
Regulatory Accounting
Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission
(FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge
customers for interstate transportation and storage of natural gas. From time to time, certain
revenues collected may be subject to possible refunds upon final FERC orders. Accordingly,
estimates of rate refund reserves are recorded considering third-party regulatory proceedings,
advice of counsel, our estimated risk-adjusted total exposure, market circumstances and other
risks. Our current rates were approved pursuant to a rate settlement. As a result, our current
revenues are not subject to refund.
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. (See Note 9 for further discussion.)
Basis of Presentation
The financial statements prior to 2010 included the accounts of Northwest and Northwest
Pipeline Services, LLC (Services Company), which was a variable interest entity (VIE) for which
Northwest was considered the primary beneficiary. As a result of Williams strategic restructuring
on February 17, 2010, which reorganized entities under common control, we have reevaluated the
status of the Services Company as a consolidated VIE and have concluded that the Services Company
is no longer considered a VIE, and therefore, will no longer be consolidated.
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The Accounting Standards Codification (Topic 250), Accounting Changes and Error Corrections,
requires that when a change in the reporting entity occurs, the change shall be retrospectively
applied to the financial statement of all prior periods to show financial information for the new
reporting entity.
The impact of these retrospective adjustments decreased accrued employee costs and increased
accounts payable to affiliated companies as of December 31, 2009. These retrospective adjustments
had no impact on net income.
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.
We provide for depreciation using the straight-line method at FERC prescribed rates, including
negative salvage (cost of removal) for transmission and storage facilities. Depreciation of general
plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a
negative salvage component that we currently collect in rates. Depreciation rates used for major
regulated gas plant facilities at December 31, 2010, 2009 and 2008 are as follows:
Category of Property | ||||
Storage facilities |
0.15%-2.23 | % | ||
Onshore transmission facilities |
0.15%-7.25 | % |
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.
We recorded regulatory credits totaling $1.7 million in 2010, $2.4 million in 2009, and $2.6
million in 2008 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 $32.5 million at December 31, 2010, and $30.8 million at
December 31, 2009. Such amounts will be amortized over the primary terms of the shipper agreements
as such costs are collected through rates.
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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 expected
timing of the future abandonment of the underlying physical assets. Measurement of AROs includes,
as a component of future expected costs, an estimate of the price that a third party would demand,
and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes
referred to as market-risk premium. 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, and is
being amortized to expense consistent with the amounts collected in rates. The regulatory asset
balances as of December 31, 2010 and 2009 were $40.5 million and $33.8 million, respectively. The
full amount of the regulatory asset is expected to be recovered in future rates.
The negative salvage component of accumulated depreciation ($33.6 million and $29.5 million at
December 31, 2010 and 2009, 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 10 percent for 2010 and 9
percent for 2009 and 2008. Equity AFUDC of $1.9 million, $2.0 million and $0.8 million for 2010,
2009 and 2008, 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
Through January 31, 2010, we were a participant in Williams cash management program and made
advances to and received advances from Williams. In accordance with Williams restructuring of its
business, our participation in the Williams cash management program was terminated. In 2010, our
management committee authorized cash distributions 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 were not available to us as working
capital. As a result of the restructuring, we became a participant in the WPZ cash management
program. The advances are represented by demand notes. Advances are stated at the historical
carrying amounts. Interest income is recognized when chargeable and collectability is reasonably
assured. The interest rate on the WPZ demand notes is based upon the overnight investment rate
paid on WPZs excess cash, which was approximately 0.06 percent at December 31, 2010. The interest
rate on the Williams demand notes was based upon the overnight investment rate paid on Williams
excess cash, which was 0.05 percent at December 31, 2009.
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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.
Following our conversion to a general partnership on October 1, 2007, we are no longer subject
to federal and state income tax. We are subject to local income tax in some areas where we
operate. (See Note 5.)
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, 2010, 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 $44.6 million, $44.5 million and $43.1 million in 2010, 2009
and 2008, respectively.
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2. 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, the 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 for mercury and other constituents to bring the
sites up to Washingtons current environmental standards. At December 31, 2010, we had accrued
liabilities totaling approximately $8.4 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 are also subject to the Federal Clean Air Act (the Act) and to the Federal Clean Air Act
Amendments of 1990, which added significantly to the existing requirements established by the Act.
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS)
for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone
non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008
NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and
were protective of both public health and the environment. As a result, the EPA delayed
designation of new eight-hour ozone non-attainment areas under the 2008 standards until the
reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level
ozone NAAQS from the March 2008 levels. The EPA currently anticipates finalization of the new
ground-level ozone standard in the third quarter of 2011. Designation of new eight-hour ozone
non-attainment areas are expected to result in additional federal and state regulatory actions that
will likely impact our operations and increase the cost of additions to property, plant and
equipment. We are unable at this time to estimate the cost of additions that may be required to
meet the new regulation.
Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous
air pollutants (NESHAP) regulations that will impact our operations. The emission control
additions required to comply with hazardous air pollutant regulations are estimated to include
costs in the range of $6 million to $9 million through 2013, the compliance date.
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Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October
30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide
(CO2) equivalent per year from stationary fossil-fuel combustion sources to report GHG
emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. Subsequently, the
EPA proposed additional reporting requirements on April 12, 2010 to address fugitive/vented GHG
emissions from petroleum and natural gas facilities. The EPA promulgated additional reporting
requirements for fugitive/vented emissions on November 30, 2010, with an effective date of January
1, 2011. Facilities that emit 25,000 metric tons or more CO2 equivalent per year from
stationary fossil-fuel combustion and fugitive/vented sources combined are required to report GHG
combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012 for calendar
year 2011. Compliance with this reporting obligation is estimated to cost $3 million to $5 million
over the next four to five years.
In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen
dioxide (NO2) National Ambient Air Quality Standard. The effective date of the new
NO2 standard was April 12, 2010. This new standard is subject to numerous challenges in
the federal court. We are unable at this time to estimate the cost of additions that may be
required to meet this new regulation.
Safety Matters
Pipeline Integrity Regulations We have developed an Integrity Management Program 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. The rule requires gas pipeline operators to develop an integrity
management program for transmission pipelines that could affect high consequence areas in the event
of pipeline failure. The Integrity Management Program includes a baseline assessment plan along
with periodic reassessments to be completed within required timeframes. In meeting the integrity
regulations, we have identified high consequence areas and developed our baseline assessment plan.
We are on schedule to complete the required assessments within the required timeframes. Currently,
we estimate that the cost to complete the required initial assessments over the period of 2011
through 2012 and associated remediation will be primarily capital in nature and range between $50
million and $60 million. Ongoing periodic reassessments and initial assessments of any new high
consequence areas will be completed within the timeframes required by the rule. 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
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 $9.4 million at December 31, 2010.
Cash Distributions to Partners
During January 2011, we declared and paid equity distributions of $26 million to WPZ.
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3. DEBT, FINANCING ARRANGEMENTS, AND LEASES
Long-Term Debt
Long-term debt consists of the following:
December 31, | ||||||||
2010 | 2009 | |||||||
(Thousands of Dollars) | ||||||||
5.95% senior unsecured notes due 2017 |
$ | 184,599 | $ | 184,535 | ||||
6.05% senior unsecured notes due 2018 |
249,506 | 249,440 | ||||||
7% senior unsecured notes due 2016 |
174,698 | 174,643 | ||||||
7.125% senior unsecured notes due 2025 |
84,831 | 84,819 | ||||||
Total long-term debt |
$ | 693,634 | $ | 693,437 | ||||
There are no maturities applicable to long-term debt outstanding for the next five years.
In the second quarter of 2006, we entered into certain forward starting interest rate swaps
prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date
of the June 2006 debt issuance, hedged the variability of forecasted interest payments arising from
changes in interest rates prior to the issuance of our fixed rate debt. The settlement resulted in
a gain that is being amortized to reduce interest expense over the life of the related debt.
Restrictive Debt Covenants
At December 31, 2010, none of our debt instruments restrict the amount of distributions to our
parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond
certain levels.
Revolving Credit and Letter of Credit Facility
Prior to Williams restructuring of its business, we participated in Williams unsecured $1.5
billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. 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, under certain conditions,
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 December 31, 2010, the
full $400 million under the New Credit Facility was available.
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 an applicable margin, or (2) a periodic fixed rate equal to London Interbank Offered Rate
(LIBOR) plus an 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 based
on the specific borrowers senior unsecured long-term debt ratings.
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The New Credit Facility contains various covenants that limit, among other things, the
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, with EBITDA measured on a rolling four-quarter basis) of no greater than 5.00 to 1.00 for
itself and its consolidated subsidiaries. For us, 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 is
tested at the end of each fiscal quarter (with the first full year measured on an annualized
basis). At December 31, 2010, we are in compliance with these covenants.
The New Credit Facility includes customary events of default. 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.
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) | ||||
2011 |
$ | 2,469 | ||
2012 |
2,469 | |||
2013 |
2,469 | |||
2014 |
2,469 | |||
2015 |
2,495 | |||
Total |
$ | 12,371 | ||
Operating lease rental expense, net of sublease revenues, amounted to $2.2 million, $3.6
million, and $4.9 million for 2010, 2009 and 2008, respectively.
4. BENEFIT PLANS
Certain of the benefit costs charged to us by Williams associated with employees who directly
support us are described below. Additionally, allocated corporate expenses from Williams to us
also include amounts related to these same employee benefits, which are not included in the amounts
presented below.
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Pension and Other Postretirement Benefit Plans
Williams has noncontributory defined benefit pension plans that provide pension benefits for
its eligible employees. Pension expense charged to us by Williams was $6.1 million in 2010, $7.5
million in 2009 and $3.5 million in 2008.
Williams provides certain retiree health care and life insurance benefits for eligible
participants that generally were employed by Williams on or before December 31, 1991. No other
postretirement benefit expense was recognized in 2010, 2009 or 2008, as such costs are not
currently being recovered in our rates. (See Note 9.)
Defined Contribution Plan
Williams charged us compensation expense of $2.2 million in 2010, $2.2 million in 2009 and
$2.1 million in 2008 for Williams company matching contributions to this plan.
Stock-Based Compensation
Plan Information
The Williams Companies, Inc. 2007 Incentive Plan, as restated and amended on February 23,
2010, (Plan) was approved by stockholders on May 20, 2010. 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 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
Williams 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, 2010, 2009 and 2008 was $1.4 million, $1.3 million and $1.0 million,
respectively, excluding amounts allocated from WGP and Williams.
5. INCOME TAXES
As a partnership, we are generally not subject to federal or state and local income taxes.
We do incur income tax in jurisdictions that impose their tax on partnerships, including Multnomah
County, Oregon, Business Income Tax. For the year ended December 31, 2010, we recorded current
local income tax for Multnomah County, Oregon, of $43 thousand. No income tax expense was recorded
in 2009 or 2008.
Cash payments for income taxes of $31 thousand were made to Williams in 2010. No cash
payments for federal and state income taxes were made to or received from Williams in 2009 or 2008.
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6. 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. The carrying amount and estimated fair value of our
long term debt, including current maturities, were $693.6 million and $796.1 million, respectively,
at December 31, 2010, and $693.4 million and $754.8 million, respectively, at December 31, 2009.
7. 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, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(Thousands of Dollars) | ||||||||||||
Puget Sound Energy, Inc. |
$ | 95,564 | $ | 94,508 | $ | 89,988 | ||||||
Northwest Natural Gas Co. |
48,022 | 49,256 | (a | ) |
(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
Through January 31, 2010, we were a participant in Williams cash management program and made
advances to and received advances from Williams. In accordance with Williams restructuring of its
business, our participation in the Williams cash management program was terminated. As of
December 31, 2010, no cash advances to Williams remain outstanding. The balance owed by Williams
to us pursuant to the cash management program at December 31, 2009 is reflected as a reduction of
our Owners Equity as the advances were not available to us as working capital. As a result of the
restructuring, we became a participant in WPZs cash management program. At December 31, 2010, the
advances due to us by WPZ totaled $45.0 million. The advances are represented by demand notes.
The interest rate on the Williams 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. The interest rate on the WPZ demand notes is based upon the overnight
investment rate paid on WPZs excess cash, which was approximately 0.06 percent at December 31,
2010. We received interest income from advances to our affiliates of $27 thousand, $74 thousand
and $813 thousand during the years ended December 31, 2010, 2009, and 2008, respectively. Such
interest income is included in Other Income net: Interest income Affiliated on the
accompanying Statements of Income.
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NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
Williams charges its subsidiary companies for management services provided by it and
other affiliated companies. Such corporate expenses charged by Williams, WPZ, and other affiliated
companies were $34.1 million, $36.0 million and $32.7 million for the years ended December 31,
2010, 2009 and 2008, respectively. These expenses are included in General and administrative
expense on the accompanying Statements of Income. Management considers the cost of these services
to be reasonable.
Northwest has no employees. Services are provided to us by an affiliate, NPS. In return, we
reimburse NPS for all direct and indirect expenses it incurs or payments it makes (including
salary, bonus, incentive compensation, pension and other benefits) in connection with these
services. We were billed $60.6 million, $60.1 million and $53.6 million in the years ended
December 31, 2010, 2009 and 2008, respectively. Such expenses are primarily included in General
and administrative and Operation and maintenance expenses on the accompanying Statement of
Income.
During the periods presented, our revenues include transportation transactions and rental of
communication facilities with subsidiaries of Williams. Combined revenues for these activities
totaled $6.8 million, $9.9 million, and $14.8 million for the years ended December 31, 2010, 2009,
and 2008, respectively.
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 Statements of Income. The lease was terminated on August 1, 2009.
In October 2010, Williams Partners Operating LLC made a $15.0 million capital contribution to
us to fund a portion of our expenditures for additions to property, plant and equipment.
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.
8. ASSET RETIREMENT OBLIGATIONS
We record an asset and a liability equal to the present value of each expected future ARO.
The ARO asset is depreciated in a manner consistent with the depreciation of the underlying
physical asset. We measure changes in the liability due to passage of time by applying an interest
method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are
recognized as an increase to a regulatory asset which will be amortized commensurate with our
collection of those costs in rates.
During 2010 and 2009, our overall asset retirement obligation changed as follows (in
thousands):
2010 | 2009 | |||||||
Beginning balance |
$ | 86,749 | $ | 82,666 | ||||
Accretion |
6,058 | 6,068 | ||||||
New obligations |
27 | 2,594 | ||||||
Changes in estimates
of existing obligations
(1) |
(27,679 | ) | (4,579 | ) | ||||
Ending Balance |
$ | 65,155 | $ | 86,749 | ||||
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NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
(1) | Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rates, current estimates for removal cost, discount rates, and the estimated remaining life of assets. |
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.
9. 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. Current regulatory liabilities are included in other accrued liabilities and
noncurrent 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 or refundable over various periods. Below are the details of our regulatory assets and
liabilities as of December 31, 2010 and 2009:
2010 | 2009 | |||||||
(Thousands of Dollars) | ||||||||
Current regulatory assets |
||||||||
Environmental costs |
$ | 2,200 | $ | 2,200 | ||||
Fuel recovery |
45 | 52 | ||||||
Total current regulatory assets |
2,245 | 2,252 | ||||||
Noncurrent regulatory assets |
||||||||
Environmental costs |
3,317 | 3,590 | ||||||
Grossed-up deferred taxes on
equity funds used during
construction |
17,458 | 18,346 | ||||||
Levelized depreciation |
32,463 | 30,801 | ||||||
Asset retirement obligations, net |
6,938 | 4,295 | ||||||
Total noncurrent regulatory assets |
60,176 | 57,032 | ||||||
Total regulatory assets |
$ | 62,421 | $ | 59,284 | ||||
Current regulatory liabilities |
||||||||
Fuel recovery |
$ | 731 | $ | 337 | ||||
Noncurrent regulatory liabilities |
||||||||
Postretirement benefits |
16,264 | 15,134 | ||||||
Total regulatory liabilities |
$ | 16,995 | $ | 15,471 | ||||
The significant regulatory assets and liabilities include:
Environmental Costs We have accrued liabilities for assessment and remediation activities to
bring certain sites up to current environmental standards. The accrual for these liabilities is
offset by a
44
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NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
regulatory asset. The regulatory asset is being amortized to expense consistent with
amounts collected in rates.
Fuel Recovery These amounts reflect the value of the cumulative volumetric difference
between the gas retained from our customers and the gas consumed in operations. These amounts are
not included in the rate base, but are expected to be recovered or refunded by changing the fuel
reimbursement factor in subsequent fuel filings.
Grossed-Up Deferred Taxes on Equity Funds Used During Construction The regulatory asset
balance was established to offset the deferred tax for the equity component of the allowance for
funds used during the construction of long-lived assets. Taxes on capitalized funds used during
construction and the offsetting deferred income taxes are included in the rate base and are
recovered over the depreciable lives of the long-lived asset to which they relate.
Levelized Depreciation Levelized depreciation allows contract revenue streams to remain
constant over the primary contract terms by recognizing lower than book depreciation in the early
years and higher than book depreciation in later years. The depreciation component of the
levelized incremental rates will equal the accumulated book depreciation by the end of the primary
contract terms. The difference between levelized depreciation and straight-line book depreciation
is recorded in a FERC approved regulatory asset or liability and is extinguished over the
levelization period.
Asset Retirement Obligations We record an asset and a liability equal to the present value
of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected
future abandonment of the underlying physical assets. 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, and is being amortized to expense consistent with the amounts collected in
rates.
Postretirement Benefits We seek to recover the actuarially determined cost of postretirement
benefits through rates that are set through periodic general rate filings. Any differences between
the annual actuarially determined cost and amounts currently being recovered in rates are recorded
as regulatory assets or liabilities and collected or refunded through future rate adjustments.
These amounts are not included in the rate base, and we are not currently recovering postretirement
benefit costs in our rates.
45
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NORTHWEST PIPELINE GP
QUARTERLY FINANCIAL DATA
(Unaudited)
(Unaudited)
The following is a summary of unaudited quarterly financial data for 2010 and 2009:
Quarter of 2010 | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
(Thousands of Dollars) | ||||||||||||||||
Operating revenues |
$ | 106,110 | $ | 102,578 | $ | 103,562 | $ | 109,567 | ||||||||
Operating income |
50,291 | 45,419 | 48,348 | 50,722 | ||||||||||||
Net income |
37,883 | 34,378 | 37,673 | 39,593 |
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 |
46
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Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
ITEM 9A. | 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.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was
performed as of the end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our Senior Vice President
and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our
Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable
assurance level.
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 2010 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls over financial reporting.
Item 9B. | OTHER INFORMATION |
None.
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PART III
Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K,
the information required by Items 10, 11, 12, and 13 is omitted.
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:
2010 | 2009 | |||||||
(Thousands of Dollars) | ||||||||
Audit Fees |
$ | 791 | $ | 862 | ||||
Audit-Related Fees |
| | ||||||
Tax Fees |
| | ||||||
All Other Fees |
| | ||||||
$ | 791 | $ | 862 | |||||
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 WPZ, we do not have a separate audit committee. The policies
and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board
of Directors of WPZs general partner have been set forth in WPZs 2010 annual report on Form 10-K,
which is available on the SECs website at http://www.sec.gov and on WPZs website at
http://williamslp.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 2010 | ||
Form 10-K | ||
24 | ||
25 | ||
26 | ||
27 | ||
29 | ||
30 | ||
31 | ||
32 |
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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, 2010: |
||||||||||||||||
Reserve for doubtful receivables |
$ | | $ | | $ | | $ | | ||||||||
Reserve for obsolescence of
materials and supplies |
11 | 622 | (20 | ) | 613 | |||||||||||
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 |
All other schedules have been omitted because they are not required to be filed.
(a) 3 and b. Exhibits:
Exhibit | Description | |
2(a)
|
Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007) and incorporated herein by reference. | |
3(a)
|
Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, 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 our report on Form 8-K, 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 our Registration Statement on Form S-3, 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 our report on Form 8-K, 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 our report on Form 8-K, 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 (Exhibit 4.1 to our 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., No. 1-4174, report on Form 8-K filed May 1, 2006) 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., No. 1-4174, report on Form 8-K filed May 15, 2007) and incorporated herein by reference. |
50
Table of Contents
Exhibit | Description | |
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., No. 1-4174, report on Form 8-K, filed November 28, 2007) 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 our report on Form 8-K, 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 our report on Form 8-K, filed January 30, 2008) and incorporated herein by reference. | |
10(f)
|
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, No. 1-32599, report on Form 8-K, filed on February 22, 2010) and incorporated herein by reference. | |
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. | |
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. | |
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 | |
** | Furnished herewith |
51
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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 24, 2011
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/ Randall L. Barnard
|
Senior Vice President and Management Committee Member | |
Randall L. Barnard
|
(Principal Executive Officer) | |
/s/ Richard D. Rodekohr
|
Vice President and Treasurer | |
Richard D. Rodekohr
|
(Principal Financial Officer) | |
/s/ Allison G. Bridges
|
Vice President | |
Allison G. Bridges |
||
/s/ R. Rand Clark
|
Controller (Principal Accounting Officer) | |
R. Rand Clark |
||
/s/ Donald R. Chappel
|
Management Committee Member | |
Donald R. Chappel |
Date: February 24, 2011
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EXHIBIT INDEX
Exhibit | Description | |
2(a)
|
Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007) and incorporated herein by reference. | |
3(a)
|
Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, 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 our report on Form 8-K, 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 our Registration Statement on Form S-3, 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 our report on Form 8-K, 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 our report on Form 8-K, 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 (Exhibit 4.1 to our 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., No. 1-4174, report on Form 8-K filed May 1, 2006) 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., No. 1-4174, report on Form 8-K filed May 15, 2007) 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., No. 1-4174, report on Form 8-K, filed November 28, 2007) 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 our report on Form 8-K, 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 our report on Form 8-K, filed January 30, 2008) and incorporated herein by reference. | |
10(f)
|
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, No. 1-32599, report on Form 8-K, filed on February 22, 2010) and incorporated herein by reference. |
Table of Contents
Exhibit | Description | |
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. | |
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. | |
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 | |
** | Furnished herewith |