SECURITIES AND EXCHANGE COMMISSION
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| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20112014 |
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-7414
(Exact name of registrant as specified in its charter)
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| DELAWARE | | 26-1157701 |
(State or other jurisdiction of incorporation or organization)
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Salt Lake City, Utah
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| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code: (801) 583-8800
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
None
NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ¨ No xþ
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 ¨ No xþ
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 xþ No ¨ 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 xþ No ¨
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 registrant’s 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. xþ 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):
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| Large accelerated filer | | ¨ | | Accelerated filer | | ¨ |
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| Non-accelerated filer | | þx (Do not check if a smaller reporting company) | | Smaller reporting company | | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No xþ
DOCUMENTS INCORPORATED BY REFERENCE:
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.
We use the following gas measurements in this report:
Mdth-means thousand dekatherms. MMdth-means million dekatherms.
Northwest Pipeline
GPLLC (Northwest)
is at times referred to in the first person as “we,” “us” or “our.”Northwest is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams),. On February 2, 2015, Williams completed the merger of its two consolidated master limited partnerships, the former Access Midstream Partners, L.P. (ACMP) and Williams Partners L.P. ACMP was the surviving partnership and was subsequently renamed WPZ. Williams currently holds an approximate 7260 percent interest in WPZ, comprised of an approximate 7058 percent limited partner interest and all of WPZ’s 2 percent general partner interest.
GENERAL
In this report, Northwest ownsis at times referred to in the first person as “we,” “us” or “our.”
GENERAL
We own and
operatesoperate 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
477,000472,000 horsepower. At December 31,
2011,2014, we had long-term firm transportation contracts
including peaking service,and storage redelivery agreements, with aggregate capacity reservations of approximately
3.83.9 MMdth 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 inown and operate a Liquefied Natural Gas (LNG)
storage facility near Plymouth,
Washington, that we own and operate.Washington. We have approximately
14.014.2 MMdth 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 majorour 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
2011,2014, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for approximately
22.824.1 percent and
10.910.8 percent, respectively, of our total operating revenues for the year ended December 31,
2011.2014. 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
the 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.
CAPITAL PROJECTS
North and South Seattle Lateral Delivery Expansions
We have executed agreements with Puget Sound Energy to expand the North and South Seattle laterals and provide additional lateral capacity of approximately 84 Mdth per day and 74 Mdth per day, respectively. We estimate the expansion of the two laterals to cost between $28 million and $30 million. North Seattle is scheduled for a fall 2012 in-service date and South Seattle is scheduled for a fall 2013 in-service date.
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.
Pursuant to the terms of our most recent rate settlement agreement, we must file a new rate case to be
Our current rates became effective
no later than January 1,
2013.2013, and will remain in effect for a minimum of 3 years and a maximum of 5 years.
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 FERC’s 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 operations are subject to federal environmental laws and regulations as well as the state and local laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:
Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities, and storage tanks;
Damage to facilities resulting from accidents during normal operations;
Damages to equipment and facilities resulting from storm events or natural disasters;
Blowouts, cratering, and explosions.
In addition, we may be liable for environmental damage caused by former operators of our properties.
We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines, and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.
For additional information regarding the potential impact of federal, state or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors–We are subject to risks associated with climate changeand – Our operations are subject to governmentalenvironmental laws and regulations, including laws and regulations relating to the protection of the environment,climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures, and could exceed current expectations,” and “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note 2.3. Contingent Liabilities and Commitments – Environmental Matters.” Safety and Maintenance
Pipeline Integrity RegulationsWe
Our operations are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, by Title I of the Pipeline Safety Act of 1979, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and JobJobs Creation Act of 2011 (Pipeline Safety Act), which regulateregulates safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.
Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions
for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.
On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.
Pipeline Integrity RegulationsWe have developed an Integrity Management ProgramPlan that we believe meetscomplies with the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) 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 Programprogram 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 theThe required assessmentspipeline segments originally identified for assessment were completed within the required timeframes. Currently, we estimate thattimeframe, with one exception which was reported to PHMSA.
Reassessments of the
cost to complete theoriginal segments have begun as required
initial assessments through 2012by regulations. As new pipelines are constructed and
associated remediation will be primarily capital in nature and range between $30 million and $35 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas
willare created, additional pipeline segments are required to be
completed withinadded to the
timeframes required by the rule.baseline assessment plan. These segments are also on schedule as required. 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.
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, 2012, Northwest Pipeline Services LLC had 455 employees.and its affiliates.
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
6.7. Transactions with Major Customers and Affiliates.”
FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE
“SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s 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
or phrases such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,
” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,
” “guidance,” “outlook,” “in service date,” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
Amounts and nature of future capital expenditures;
Expansion and growth of our business and operations;
Financial condition and liquidity;
Business strategy;
Cash flow from operations or results of operations;
Rate case filings; and
Natural gas prices, supply, and demand.demand; and
Demand for our services.
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, market demand, and volatility of prices, and the availability and cost of capital;prices;
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;competitors and the effects of competition;
Whether we are able to successfully identify, evaluate, and execute investment opportunities;
Development of alternative energy sources;
The impact of operational and development hazards;hazards and unforeseen interruptions;
Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve)environmental regulations), 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 and counterparties;
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;capital;
Risks associated with future weather and natural phenomenon, including climate conditions;
Acts of terrorism, including cybersecurity threats and related disruptions; 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.
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 and hazards that might result in accidents and other operating risks and hazardsunforeseen interruptions. Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural
gas. These operating risks include,gas including, but
are not limited to:
Fires, blowouts, cratering, and explosions;
Uncontrolled releases of natural gas;
Pollution and other environmental risks;
agingAging infrastructure and mechanical problems;
Damages to pipelines and pipeline blockages or other pipeline interruptions;
Operator error; and
Damage caused by third party activity, such as operation of construction equipment; andequipment.
terrorist attacks or threatened attacks on our facilities or thoseAny of other energy companies.
Thesethese risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, 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, anAn 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
Certain of our services are subject to long-term, discounted or negotiated rate contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
We provide some services pursuant to long-term, fixed-price 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 the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other operating risks could further result in lossfactors relating to the specific facilities being used to perform the services.
We may not be able to extend or replace expiring natural gas transportation and storage contracts at favorable rates, on a long-term basis or at all.
Our primary exposure to market risk occurs at the time the terms of
service availableexisting transportation and storage contracts expire or are subject to
our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segmentstermination. Upon expiration or termination of our
pipeline infrastructure. Potential customer impacts arising from service interruptionsexisting contracts, we may not be able to extend such contracts with existing customers or obtain replacement contracts at favorable rates, on
segmentsa long-term basis or at all. Failure to extend or replace a significant portion of our
pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing
customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, withcontracts may have a
resulting negative impactmaterial adverse effect on our business, financial condition, results of operations and cash flows.
Increased Our ability to extend or replace existing customer contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including:
The level of existing and new competition to deliver natural gas to our markets and competition from alternative
natural gas transportation and storage options and alternative fuel sources
could have a significant financial impact on us.We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams, may not be limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, includingsuch as electricity, coal, fuel oils, or nuclear energy;
Pricing, demand, availability, and
other alternative energy sources.margins for natural gas in our markets;
Whether the market will continue to support long-term firm contracts;
The effects of regulation on us, our customers, and our contracting practices; and
Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The result of these efforts will impact our reputation and positioning in the market.
Competitive pressures could lead to decreases in the volume of natural gas contracted for or transported through our pipeline system.
The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility, and reliability. FERC’s policies promoting competitionAlthough most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the interstate natural gas markets are havingpipeline industry that have led to increased competition throughout the effect of increasing the natural gas transportation and storage options for our traditional customer base.industry. 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
We compete primarily with other interstate pipelines and storage facilities in the
amounttransportation and storage of
transportation or storage capacity contracted onnatural gas. Some of our
system or, in cases where we do notcompetitors may have
long-term fixed rate contracts, could force usgreater financial resources and access 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 pricegreater supplies 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. Allthan we do. Some 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, discountedcompetitors may expand 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 gasconstruct 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 ofsystems 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 the production basins serving us; and
the effects of state regulation on customer contracting practices.
Any failuretheir ability 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 system’s current capacity is fully contracted, FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry.compete with us. 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 willFurther, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils, and other alternative energy sources. We may not be able to successfully compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business, cash flows, and results of operations.
Any significant decrease in supplies of natural gas in
the supply basins we access or in demand for those supplies in our
areas of operationtraditional markets could adversely affect our business and operating results.
Our
ability to maintain and expand our business
is dependentdepends on the
continued availabilitylevel of drilling and production by third parties in our supply basins. 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 existing wells may also be less than anticipated, and the rate at which production
and reserves. The developmentfrom these reserves declines may be greater than anticipated. We do not obtain independent evaluations of
the additional natural gas reserves
requires significant capital expenditures by others for explorationunderlying such wells and
development drilling and the installationsupply basins with access to our pipeline. Accordingly, we do not have independent estimates of
production, gathering, storage, transportation and other facilities that permit natural gas to be produced and deliveredtotal reserves dedicated to our pipeline
system. Lowor the anticipated life of such reserves. In addition, 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.supplies. 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 also 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 gathering or 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 in the markets we serve by deliveries through our system. Any decrease in this demand could adversely affect our business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures,
alternative fuel requirements, governmental regulation,
orand technological advances in fuel economy and energy generation devices, all of which are matters beyond our control.
A failure to obtain sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could have a material adverse effect on our business, financial condition, and results of operations.
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 testing, maintaining or repairing our facilities may exceed our expectations, and the FERC
may not allow, or competition in our markets may
not allow us to recoverprevent, our recovery of such costs in the rates we charge for our services.
We
have experienced and could experience
in the future unexpected leaks or ruptures on our gas pipeline
system,system. Either as a preventative measure or
in response to a leak or another issue, we could be required by regulatory authorities to test or undertake modifications to our
systemssystems. If the cost of testing, maintaining, or repairing our facilities exceeds expectations and the FERC does not allow us to recover, or competition in our markets prevents us from recovering, such costs in the rates that
we charge for our services, such costs could
result inhave a material adverse impact on our business, financial condition, and results of
operations if the cost of testing, 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. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable, and complete. More recently, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 became law and under this statute PHMSA may issue additional regulations addressing such records. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipeline.operations.
Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.
Public and regulatory scrutiny of the energy industry has resulted in
the proposal and/or implementation of increased
regulations being either proposed or implemented.regulations. Such scrutiny has also resulted in various inquiries, investigations, and court
proceedings.proceedings, including litigation of energy industry matters. Both the shippers on our
pipelinespipeline 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, investigations, and court 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
and/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.us, which among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. 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.
In addition, existing regulations might be revised or reinterpreted
and new laws and regulations might be adopted or become applicable to us, our
facilitiescustomers, 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, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed recently, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January 3, 2012. This law will result in the promulgation ofbusiness activities. If new
regulations to be administered by PHMSA affecting the operations of our gas pipeline system including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations 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.
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 and other jurisdictions have announced or adopted programs to stabilize and reduce GHGs. In 2009, the U.S. Environmental Protection Agency (EPA) issued a final determination that six GHGs are a threat to public safety and welfare. In 2011, the EPA implemented permitting for new and/or modified large sources of GHG emissions through the existing Prevention of Signification Deterioration permitting program. Additional direct regulation of GHG emissions in our industry may be implemented under other Clean Air Act programs, including the New Source Performance Standards program.
The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costsare imposed relating to (i) operateoil and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If wegas extraction, or if additional levels of reporting, regulation, or permitting moratoria are unable to recoverrequired or pass through a significant level of our costsimposed, including those related to complying with climate change regulatory requirements imposed on us, ithydraulic fracturing, the volumes of natural gas that we transport could have a material adverse effect ondecline and our results of operations and financial condition. 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. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
adversely affected.
Our operations are subject to
governmentalenvironmental laws and regulations, including laws and regulations relating to
the protection of the environment,climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures
andthat could exceed our
current expectations.
Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in
natural gasthe gathering, transportation, and storage
operations,of natural gas as well as waste disposal practices and
as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, Native American, and local laws and regulations governing environmental protection, the discharge of materials into the environment, and the security of chemical and industrial facilities. These laws include:construction activities. 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 and storm water from our facilities to state and federal waters, including wetlands;
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;
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;
Endangered Species Act (ESA), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and
Oil Pollution Act (OPA) of 1990, which requires oil storage facilities and vessels to submit plans to the federal government detailing how they will respond to large discharges, regulates petroleum storage tanks and related equipment, and imposes liability for spills on responsible parties.
Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs, analogous state agencies and tribal governments, 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, andand/or 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, and delays in granting permits and cancellationpermits.
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 materials associated with natural gas,
oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline
system 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-compliancenoncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or
oil and natural gas operations or facilities, 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.In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. We cannot predict what the results of this initiative would be, or whether federal, state, or local laws or regulations will be enacted in this area. If regulations were imposed related to oil and gas extraction, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.
Our business may be adversely affected by changed regulations and 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 or construction 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 connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
Hydraulic fracturing is exempt from federal regulation pursuant to
In addition, climate change and the
federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered or implemented. Legislation to further regulate hydraulic fracturing has been proposed in Congress. The U.S. Department of Interior has announced plans to formalize obligations for disclosure of chemicalscosts that may be associated with
hydraulic fracturing on federal lands. The resultsits impacts and with the regulation of
a pending EPA investigation by a committeeemissions of
greenhouse gases (GHG) have the
House of Representatives and two recent reportspotential to affect our business. Regulatory actions by the U.S.
DepartmentEnvironmental Protection Agency or the passage of
Energy’s Shale Gas Subcommittee could lead to further restrictions on hydraulic fracturing. The EPA has proposed regulations under the CAA regarding certain emissions from the hydraulic fracturing of oil and natural gas wells and announced its intention to propose regulations by 2014 under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production. In addition, some state and local authorities have considered or imposed new
laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, disclosure obligations and temporary or permanent bans on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. We cannot predict whether any additional federal, state or localclimate change laws or regulations
will be enactedcould result in
this areaincreased costs to (i) operate and
if so, what their provisions would be.maintain our facilities, (ii) install new emissions controls on our facilities, and (iii) administer and manage any GHG emissions program. If
additional levelswe are unable to recover or pass through a significant level of
reporting, regulation or permitting moratoria were required or imposedour costs related to
hydraulic fracturing, the volumes of natural gas that we transport,complying with climate change regulatory requirements imposed on us, it could
decline andhave a material adverse effect on our results of 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. Iffinancial condition. To the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions and expectations may alsoextent financial markets view climate change and any new capital costs incurredGHG emissions as a financial risk, this could negatively impact our cost of and access to comply with such changes may not be recoverable undercapital. Climate change and GHG regulation could also reduce demand for our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our products and 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.
services.
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 extensions or replacements of these contracts on favorable terms, if at all. For the year ended December 31,
2011,2014, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company. These customers accounted for approximately
33.724.1 percent
and 10.8 percent, respectively, of our operating revenues for the year ended December 31,
2011.2014. The loss of all, or even a portion of, the revenues from contracted volumes supplied by
theseour key 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 counterparties, 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
and counterparties 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 wouldOur customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be
suddenly and disparately impacted by,
among other factors, commodity price volatility, deteriorating
energy market conditions,
in the economy, including declines in our customers’ creditworthiness.and public and regulatory opposition to energy producing activities. If we fail to adequately assess the creditworthiness of existing or future customers
and counterparties, 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.
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
interconnectinterconnection 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
risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
We are
In accordance with customary industry practice, we maintain insurance against some, but not
fully insured against all, risks
inherentand losses, and only at levels we believe to
our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.be appropriate.
Williams currently maintains excess liability insurance with limits of
$610$695 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, 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
(NGL) operations.
Although we maintain property insurance on certain physical assets that 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 insureself-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 to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured
member of OIL, Williams shares in the losses among other OIL members even if our property is not damaged. As a result, we may share in any losses incurred by Williams.
Furthermore, 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 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
We may not be able to grow or effectively manage our growth.
As part of our
growth strategy, we consider acquisition opportunities and engage in significant capital
projects subjects usprojects. We have a project lifecycle process and an investment evaluation process. These are processes we use to
constructionidentify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks
increasesor our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in
labor costs and materials, and other risks that may adversely affect financial results.a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, fractionation, or storage facilities, or olefins processing facilities, as well as the expansion of existing facilities. Construction or expansion of these facilities is subjectWe also face all the risks associated with construction. These risks include the inability 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, materials, permits, rights-of-way, and materials to complete expansion projects;
potential changesother required inputs 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 basismanner such that projects are completed on time and on acceptable terms;
the ability to construct projects within estimated costs, including the risk ofthat construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:
Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;
We could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;
Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from inflationexisting operations, and make it difficult to maintain our current business standards, controls, and procedures; and
Acquisitions and capital projects may require substantial new capital, either by the issuance of debt or increased costs of equipment, materials, labor or other factors beyond our control, thatequity, and we may not be material; and
the abilityable to access capital markets to fund construction projects.
or obtain acceptable terms.Any
If realized, 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 affecthave an adverse impact on 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 issue new rules 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
Failure of our assets. This relianceservice providers or disruptions to outsourcing relationships might negatively impact our ability to conduct our business.
We rely on
others to operate our assets and to provide other services could adversely affect our business and operating results.Williams and other third parties operatefor certain ofservices necessary for us to be able to conduct our assets.business. We have a limited ability to control these operations and the associated costs. The successCertain of these operations is therefore dependent upon a number of factorsWilliams’ accounting and information technology functions that we rely on are outside our control, including the competencecurrently provided by third party vendors, and financial resourcessometimes from service centers outside of the operators.
We rely on Williams for certainUnited States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of 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 Williams’ relationships with its outsourcingbetween providers could lead to delays inloss of institutional knowledge or interruptions of these services.service disruptions. Our reliance on Williams and others as operatorsservice providers 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
the amount of our
leverageindebtedness may affect our future financial and operating flexibility.
Our total outstanding long-term debt, as of December 31,
2011,2014, was
$693.8$694.4 million.
The agreements governing our indebtedness contain covenants that restrict our ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ and WPZ’s debt agreements contain similar covenants with respect to such entities and their respective subsidiaries, including us.
Our debt service obligations and
restrictivethe covenants
in our credit facility and the indentures governing our senior unsecured notesdescribed above could have important consequences. For example, they
could:could, among other things: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;indebtedness;
Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions,general limited liability company purposes, 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 partnershiplimited liability company purposes, or other purposes; and
Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;operate, including by limiting our ability to expand or pursue our business activities and
Place by preventing us at a competitive disadvantage comparedfrom engaging in certain transactions that might otherwise be considered beneficial to our competitors that have proportionately less debt.us.
Our ability to comply with our debt covenants, 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.performance. 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 comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, ifor at all, we could
be forced to restructure or refinance our indebtedness, seek additional equity capital, or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
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 WPZ’s 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 WPZ’s 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 all or substantially all of our assets. In addition, our credit facility contains certain financial covenants and restrictions on our ability and our material subsidiaries’ ability to grant certain liens to support indebtedness, our ability to merge or consolidate or sell all or substantially all of our assets, allow any material change in the nature of our business, enter into certain affiliate transactions, and make certain distributions during the continuation of an event of default. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.
Williams’ and WPZ’s 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 WPZ’s 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 WPZ’s ability to comply with these covenants may be negatively impacted.
Our failure to comply with the covenants in
the documents governing our
debt agreementsindebtedness could result in events of
default. Upon the occurrence ofdefault, which could render such
an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediatelyindebtedness due and
payable and terminate all commitments, if any,payable. We may not have sufficient liquidity to
extend further credit. Certain payment defaultsrepay our indebtedness in such circumstances. In addition, cross-default or
an acceleration undercross-acceleration provisions in our
public indentures or other material indebtednessdebt agreements could cause a
cross-defaultdefault or
cross-acceleration of our credit facility. Such a cross-default or cross-acceleration couldacceleration to 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 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations –- Capital Resources and Liquidity.
”
Our ability to obtain credit in the future could be affected by Williams’ and WPZ’s credit ratings.
Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries.
Each of Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their
respective subsidiaries.
Williams’ and WPZ’sTheir 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
each of Williams and WPZ, our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. If Williams or WPZ were to experience
a deterioration in
theirits 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 alsocould 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.
Difficult conditions in the global
capital markets, the creditfinancial markets and the economy in general could negatively affect our business and results of operations.
Our business may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are
industrial or economic contraction leading to reduced energy demand and lower prices for our products and services
and 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 reduce our access to credit markets, raise the cost of such access or require us, WPZ or Williams to provide additional collateral to our counterparties.customers. We have availability under the 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. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.
A downgrade of our credit ratings,
which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing
business, and independent third parties outside of our control determine our credit ratings.business.
A downgrade of our credit ratings might increase our cost of borrowing and could
causerequire us to
postprovide collateral
with third parties,to our counterparties, negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit
ratings and other disruptions. Such disruptions could include:ratings.deteriorating capital market conditions;
declining market prices for natural gas;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
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,such as 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.
agencies.
WPZ 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.
We
Because we are an indirect wholly-owned subsidiary of WPZ,
whichWPZ 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
partnersmember 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
the 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
In addition to
regulation by other federal, state, and local regulatory
authorities. Specifically,authorities, under the NGA, our interstate pipeline transportation and storage services and related assets are subject to regulation by the FERC.
The federalFederal regulation extends to such matters as:
Transportation of natural gas in interstate commerce;
Rates, operating terms, types of services offered to customers, and conditions of service, including initiation and discontinuation of services;service;
The types of services we may offer to our customers;
Certification and construction of new interstate pipelinepipelines and storage facilities;
Acquisition, extension, disposition, or abandonment of existing interstate pipelinepipelines and storage facilities;
Accounts and records;
Depreciation and amortization policies;
Relationships with affiliated companies whothat 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 NGA, the 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 the FERC. In addition, the FERC prohibits providers from unduly preferring
Regulatory or
unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.Regulatoryadministrative actions in these areas, including successful complaints or protests against our rates, can affect our business in many ways, including by decreasing existing tariff rates andor setting future tariff rates to levels such that revenues are inadequate to recover increases in operating costs or to sustain an adequate return on capital investments, 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 laws governing our business.
Our operations are regulated by numerous governmental agencies, including the FERC, the EPA and PHMSA. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, the 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 and under the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day (from the prior $100,000) with a maximum of $2 million for any related series of violations (from the prior $1 million). Any material penalties or fines under these or other statutes, rules, regulations or orders 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 pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by
the FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.
Risks Related to Employees, Outsourcing of Non-Core Support Activities, and
Technology.Technology
Institutional knowledge residing with current employees nearing retirement eligibility or with
former employees
going to WPX Energy, Inc. as part of the separation of Williams’ exploration and production business might not be adequately preserved.
We expect that a significant percentage of employees will become eligible for retirement over the next several years. In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, or
with the loss of employees as part of the separation of Williams’ exploration and production business,their service is no longer available, 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 our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
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 Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as service providers 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.
Some studies indicate a high failure rate of outsourcing relationships. 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 and information technology 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
that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.
Risks Related to Weather, Other Natural Phenomena and Business Disruption
Our
assets and operations, as well as our customers’ assets and operations, can be affected by weather and other natural phenomena.
Our
assets and operations and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme
or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with
theseour 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
our or our customers’ operations or
the occurrence of 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
Given the volatile nature of the commodities we transport and store, our assets and the assets of our customers and others
in our industry may be targets of terrorist
activities thatactivities. A terrorist attack could
create significant price volatility, disrupt our business,
limit our access to capital markets, 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.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational
industrial control systems and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access
to physical locations or
information otherwise known as “social engineering.”Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. information.
Breaches in our information technology infrastructure or physical facilities, or other disruptions
including those arising from theft, vandalism, fraud, or unethical conduct, could result in damage to our assets,
unnecessary waste, safety incidents, damage to the environment,
reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
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| Item 1B. | UNRESOLVED STAFF COMMENTS |
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.
The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note
2.3. Contingent Liabilities and
Commitments – Legal Proceedings.Commitments.”
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| Item 4. | MINE SAFETY DISCLOSURES |
|
| |
| Item 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
We are
At December 31, 2014, we were indirectly owned
100 percent by
WPZ, a publicly traded master limited partnership,Williams Partners L.P., and Williams
holdsheld an approximate
7266 percent interest in
WPZ. Our partnershipWilliams Partners L.P., comprised of an approximate 64 percent limited partner interest
is not publicly traded.and all of WPZ’s 2 percent general partner interest.
We paid
$127.0$234.0 million and
$191.5$91.0 million in cash distributions
to our partners during
20112014 and
2010,2013, respectively.
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| 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.
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| Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion 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.
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. Management’s 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 Comprehensive Income for the period in which the discontinuance of
regulatory accounting treatment
occurs.occurs, unless otherwise required to be recorded under other provisions of accounting principles generally accepted in the United States. The aggregate amounts of regulatory assets reflected in the Balance Sheet are
$61.9$53.2 million and
$62.4$59.4 million at December 31,
20112014 and
2010,2013, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are
$20.9$27.4 million and
$17.0$19.9 million at December 31,
20112014 and
2010,2013, respectively. A summary of regulatory assets and liabilities is included in Note
89 of Notes to Financial Statements.
Analysis of Financial Results
This analysis discusses financial results of our operations for the years
20112014 and
2010.2013. 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.
Our
Total operating revenues
increased $12.7 million, or 3 percent, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. This increase is primarily attributed to higher reservation charges due primarily to the Sundance Trail Expansion Project that was put into service on November 1, 2010.in 2014 remained consistent with 2013. Our transportation service and gas storage service accounted for 9798 percent and 2 percent, respectively, of our operating revenues for each of the years ended December 31, 2011both 2014 and 2010, respectively. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2011 and 2010, respectively.
2013.
Total operating expenses increased
$10.2$2.2 million, or
51 percent. This increase is due primarily to
i) higher contractual services, materials and equipment of $4.6 million primarily attributed to increased expenditures on pipeline maintenance; ii) higher depreciation of
$2.6$3.0 million, attributed to property
additions; iii)additions, and higher
amortization of regulatory assets of $0.8 million, associated with levelized depreciation. These increases were partially offset by lower labor
and benefit expenses of
$1.7 million; and iv) higher allocated overhead from affiliates of $1.3 million.Recent Events
Williams incurs certain corporate general and administrative costs which are charged to its businesses, including us. We expect an increase$2.0 million, primarily associated with a reduction in retirement plan expense.
The decrease in our
proportionate share of these costs in 2012,net income is primarily due
in part to
Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011.the factors noted above.
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 inflation’s effect on costs.
CAPITAL RESOURCES AND LIQUIDITY
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 credit facility 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.
Credit Facility
In June 2011, we entered into a $2 billion five-year senior unsecured revolving credit facility agreement (Credit Facility)
We, along with WPZ and Transcontinental Gas Pipe Line
Company, LLC (Transco)
as co-borrowers. The agreement replaced, are co-borrowers under a $3.5 billion unsecured credit facility. Total letter of credit capacity available to WPZ under the
existing $1.75 billion credit facility
agreement that was scheduled to expire February 17, 2013. The Credit Facility may, under certain conditions, be increased up to an additional $400 million. The full amount of the Credit Facility is
available to WPZ.$1.125 billion. We may borrow up to
$400$500 million under the
Credit Facilitycredit facility to the extent not otherwise utilized by WPZ and
TranscoTransco.
We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2014, our advances to WPZ totaled approximately $135.1 million. These advances are represented by demand notes.
Please see “Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements: Note
3.4. Debt, Financing Arrangements, and Leases – Credit Facility and Note
6.7. Transactions with Major Customers and Affiliates – Related Party Transactions.”
We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the
existing assets, increase transmission or storage capacities from existing levels or enhance revenues. We anticipate 20122015 capital expenditures will be between $140 million and $160approximately $89 million. Of this total, $55 million to $65$36 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2012,2015, we expect to fund our capital expenditures with cash from operations.
Property, plant, and equipment additions were $115.1 million, $120.2 million and $152.6 million for 2011, 2010, and 2009, respectively.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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| Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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, 2011 | |
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 | | | (1,169 | ) |
| | | | |
Total long-term debt | | $ | 693,831 | |
| | | | |
|
| | | |
| | December 31, 2014 |
| 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% unsecured debentures due 2025 | 85,000 |
|
| | 695,000 |
|
| Unamortized debt discount | (580 | ) |
| Total long-term debt | $ | 694,420 |
|
Our total long-term debt at December 31,
20112014 had a carrying value of
$693.8$694.4 million and a fair market value of
$826.3$766.5 million. As of December 31,
2011,2014, 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
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVERFINANCIAL 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
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Management Committee of
We have audited the accompanying balance
sheetssheet of Northwest Pipeline
GPLLC as of December 31,
20112014 and
2010,2013, and the related statements of
income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31,
2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a).2014. These financial statements
and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements
and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northwest Pipeline
GPLLC at December 31,
20112014 and
2010,2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2011,2014, 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.February 27, 201225, 2015
STATEMENT OF
COMPREHENSIVE INCOME
(Thousands of Dollars)
| | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
OPERATING REVENUES | | $ | 434,484 | | | $ | 421,817 | | | $ | 434,379 | |
| | | | | | | | | | | | |
OPERATING EXPENSES: | | | | | | | | | | | | |
General and administrative | | | 59,253 | | | | 57,162 | | | | 64,657 | |
Operation and maintenance | | | 69,183 | | | | 65,516 | | | | 71,085 | |
Depreciation | | | 90,486 | | | | 87,915 | | | | 86,373 | |
Regulatory credits | | | (1,023 | ) | | | (1,662 | ) | | | (2,403 | ) |
Taxes, other than income taxes | | | 19,356 | | | | 18,106 | | | | 14,158 | |
| | | | | | | | | | | | |
Total operating expenses | | | 237,255 | | | | 227,037 | | | | 233,870 | |
| | | | | | | | | | | | |
Operating income | | | 197,229 | | | | 194,780 | | | | 200,509 | |
| | | | | | | | | | | | |
OTHER INCOME—net: | | | | | | | | | | | | |
Interest income - | | | | | | | | | | | | |
Affiliated | | | 8 | | | | 27 | | | | 74 | |
Other | | | 16 | | | | 3 | | | | 16 | |
Allowance for equity funds used during construction | | | 1,438 | | | | 1,947 | | | | 1,996 | |
Miscellaneous other expense, net | | | (108 | ) | | | (985 | ) | | | (135 | ) |
| | | | | | | | | | | | |
Total other income - net | | | 1,354 | | | | 992 | | | | 1,951 | |
| | | | | | | | | | | | |
INTEREST CHARGES: | | | | | | | | | | | | |
Interest on long-term debt | | | 44,439 | | | | 44,458 | | | | 44,439 | |
Other interest | | | 1,994 | | | | 2,664 | | | | 5,414 | |
Allowance for borrowed funds used during construction | | | (663 | ) | | | (877 | ) | | | (1,044 | ) |
| | | | | | | | | | | | |
Total interest charges | | | 45,770 | | | | 46,245 | | | | 48,809 | |
| | | | | | | | | | | | |
NET INCOME | | $ | 152,813 | | | $ | 149,527 | | | $ | 153,651 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| OPERATING REVENUES | $ | 470,050 |
| | $ | 469,661 |
| | $ | 437,835 |
|
| OPERATING EXPENSES: | | | | | |
| General and administrative | 62,085 |
| | 62,473 |
| | 68,997 |
|
| Operation and maintenance | 74,191 |
| | 75,342 |
| | 77,580 |
|
| Depreciation | 99,138 |
| | 96,109 |
| | 93,419 |
|
| Regulatory debits (credits) | 1,487 |
| | 921 |
| | (494 | ) |
| Taxes, other than income taxes | 16,987 |
| | 16,882 |
| | 16,751 |
|
| Total operating expenses | 253,888 |
| | 251,727 |
| | 256,253 |
|
| OPERATING INCOME | 216,162 |
| | 217,934 |
| | 181,582 |
|
| OTHER (INCOME) AND OTHER EXPENSES: | | | | | |
| Interest expense | 46,095 |
| | 46,177 |
| | 46,357 |
|
| Allowance for equity and borrowed funds used during construction | (573 | ) | | (1,405 | ) | | (2,291 | ) |
| Miscellaneous other expenses, net | 87 |
| | 175 |
| | 793 |
|
| Total other (income) and other expenses | 45,609 |
| | 44,947 |
| | 44,859 |
|
| NET INCOME | 170,553 |
| | 172,987 |
| | 136,723 |
|
| CASH FLOW HEDGES: | | | | | |
Amortization of cash flow hedges into Interest expense | (62 | ) | | (62 | ) | | (62 | ) |
| COMPREHENSIVE INCOME | $ | 170,491 |
| | $ | 172,925 |
| | $ | 136,661 |
|
(Thousands of Dollars)
| | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
| | |
CURRENT ASSETS: | | | | | | | | |
Cash | | $ | 37 | | | $ | 5 | |
Receivables: | | | | | | | | |
Trade | | | 38,245 | | | | 38,515 | |
Affiliated companies | | | 2,250 | | | | 2,118 | |
Advances to affiliate | | | 52,024 | | | | 45,045 | |
Materials and supplies, less reserves of $816 at December 31, 2011 and $613 at December 31, 2010 | | | 10,488 | | | | 11,719 | |
Exchange gas due from others | | | 3,441 | | | | 2,323 | |
Exchange gas offset | | | — | | | | 3,854 | |
Prepayments and other | | | 3,469 | | | | 3,415 | |
| | | | | | | | |
Total current assets | | | 109,954 | | | | 106,994 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT, at cost | | | 3,068,915 | | | | 2,965,097 | |
Less-Accumulated depreciation | | | 1,076,943 | | | | 1,017,634 | |
| | | | | | | | |
Total property, plant and equipment, net | | | 1,991,972 | | | | 1,947,463 | |
| | | | | | | | |
OTHER ASSETS: | | | | | | | | |
Deferred charges | | | 10,250 | | | | 11,817 | |
Regulatory assets | | | 59,605 | | | | 60,176 | |
| | | | | | | | |
Total other assets | | | 69,855 | | | | 71,993 | |
| | | | | | | | |
Total assets | | $ | 2,171,781 | | | $ | 2,126,450 | |
| | | | | | | | |
|
| | | | | | | |
| | December 31, 2014 | | December 31, 2013 |
| ASSETS | |
| CURRENT ASSETS: | | | |
| Cash | $ | 154 |
| | $ | 133 |
|
| Receivables: |
| |
|
| Trade | 42,759 |
| | 42,776 |
|
| Affiliated companies | 2,039 |
| | 40,427 |
|
| Advances to affiliate | 135,054 |
| | 119,168 |
|
| Other | 1,249 |
| | 1,627 |
|
| Materials and supplies | 10,066 |
| | 10,269 |
|
| Exchange gas due from others | 4,184 |
| | 2,751 |
|
| Prepayments and other | 4,881 |
| | 3,555 |
|
| Total current assets | 200,386 |
| | 220,706 |
|
| PROPERTY, PLANT AND EQUIPMENT, at cost | 3,269,617 |
| | 3,205,576 |
|
| Less-Accumulated depreciation | 1,288,530 |
| | 1,220,737 |
|
| Total property, plant and equipment, net | 1,981,087 |
| | 1,984,839 |
|
| OTHER ASSETS: |
| |
|
| Deferred charges | 4,700 |
| | 6,408 |
|
| Regulatory assets | 49,923 |
| | 58,141 |
|
| Total other assets | 54,623 |
| | 64,549 |
|
| Total assets | $ | 2,236,096 |
| | $ | 2,270,094 |
|
(Thousands of Dollars)
| | | | | | | | |
| | | December 31, | | | December 31, | |
| | | 2011 | | | 2010 | |
LIABILITIES AND OWNER’S EQUITY | | | | |
| | |
CURRENT LIABILITIES: | | | | | | | | |
Payables: | | | | | | | | |
Trade | | $ | 13,634 | | | $ | 13,177 | |
Affiliated companies | | | 8,812 | | | | 10,105 | |
Accrued liabilities: | | | | | | | | |
Taxes, other than income taxes | | | 10,252 | | | | 10,186 | |
Interest | | | 4,045 | | | | 4,045 | |
Exchange gas due to others | | | 10,472 | | | | 13,115 | |
Exchange gas offset | | | 2,241 | | | | — | |
Other | | | 5,006 | | | | 4,245 | |
| | | | | | | | |
Total current liabilities | | | 54,462 | | | | 54,873 | |
| | | | | | | | |
LONG-TERM DEBT | | | 693,831 | | | | 693,634 | |
| | |
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES | | | 103,041 | | | | 88,347 | |
| | |
CONTINGENT LIABILITIES AND COMMITMENTS (Note 2) | | | | | | | | |
| | |
OWNER’S EQUITY: | | | | | | | | |
Owner’s capital | | | 1,051,962 | | | | 1,046,862 | |
Retained earnings | | | 268,209 | | | | 242,396 | |
Accumulated other comprehensive income | | | 276 | | | | 338 | |
| | | | | | | | |
Total owner’s equity | | | 1,320,447 | | | | 1,289,596 | |
| | | | | | | | |
Total liabilities and owner’s equity | | $ | 2,171,781 | | | $ | 2,126,450 | |
| | | | | | | | |
|
| | | | | | | |
| December 31, 2014 |
| December 31, 2013 |
| LIABILITIES AND OWNER’S EQUITY |
|
| CURRENT LIABILITIES: | | | |
| Payables: | | | |
| Trade | $ | 12,709 |
| | $ | 24,013 |
|
| Affiliated companies | 13,143 |
| | 11,136 |
|
| Accrued liabilities: | | | |
| Taxes, other than income taxes | 11,246 |
| | 10,974 |
|
| Interest | 4,045 |
| | 4,045 |
|
| Exchange gas due to others | 6,406 |
| | 5,847 |
|
| Exchange gas offset | 3,941 |
| | 572 |
|
| Customer advances | 2,363 |
| | 6,371 |
|
| Other | 1,799 |
| | 1,965 |
|
| Total current liabilities | 55,652 |
| | 64,923 |
|
| LONG-TERM DEBT | 694,420 |
| | 694,224 |
|
| OTHER NONCURRENT LIABILITIES: | | | |
| Asset retirement obligations | 94,678 |
| | 60,753 |
|
| Regulatory liabilities | 23,375 |
| | 19,252 |
|
| Other | 8,017 |
| | 7,479 |
|
| Total other noncurrent liabilities | 126,070 |
| | 87,484 |
|
| CONTINGENT LIABILITIES AND COMMITMENTS (Note 3) |
| |
|
| OWNER’S EQUITY: | | | |
| Owner’s capital | 1,073,892 |
| | 1,073,892 |
|
| Retained earnings | 285,972 |
| | 349,419 |
|
| Accumulated other comprehensive income | 90 |
| | 152 |
|
| Total owner’s equity | 1,359,954 |
| | 1,423,463 |
|
| Total liabilities and owner’s equity | $ | 2,236,096 |
| | $ | 2,270,094 |
|
STATEMENT OF OWNER’S EQUITY
(Thousands of Dollars)
| | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Owner’s capital - | | | | | | | | | | | | |
Balance at beginning of period | | $ | 1,046,862 | | | $ | 1,027,862 | | | $ | 978,682 | |
Capital contribution from parent | | | 5,100 | | | | 19,000 | | | | 49,180 | |
| | | | | | | | | | | | |
Balance at end of period | | | 1,051,962 | | | | 1,046,862 | | | | 1,027,862 | |
| | | | | | | | | | | | |
Loans (to) from affiliate - | | | | | | | | | | | | |
Balance at beginning of period | | | — | | | | (105,431 | ) | | | (34,265 | ) |
Loans (to) from affiliate | | | — | | | | 105,431 | | | | (71,166 | ) |
| | | | | | | | | | | | |
Balance at end of period | | | — | | | | — | | | | (105,431 | ) |
| | | | | | | | | | | | |
Retained earnings - | | | | | | | | | | | | |
Balance at beginning of period | | | 242,396 | | | | 284,319 | | | | 265,668 | |
Net income | | | 152,813 | | | | 149,527 | | | | 153,651 | |
Cash distributions | | | (127,000 | ) | | | (191,450 | ) | | | (135,000 | ) |
| | | | | | | | | | | | |
Balance at end of period | | | 268,209 | | | | 242,396 | | | | 284,319 | |
| | | | | | | | | | | | |
Accumulated other comprehensive income (loss) - | | | | | | | | | | | | |
Balance at beginning of period | | | 338 | | | | 400 | | | | 462 | |
Cash flow hedges: | | | | | | | | | | | | |
Reclassification of gain into earnings | | | (62 | ) | | | (62 | ) | | | (62 | ) |
| | | | | | | | | | | | |
Balance at end of period | | | 276 | | | | 338 | | | | 400 | |
| | | | | | | | | | | | |
Total owner’s equity | | $ | 1,320,447 | | | $ | 1,289,596 | | | $ | 1,207,150 | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| Owner’s capital: | | | | | |
| Balance at beginning of period | $ | 1,073,892 |
| | $ | 1,060,592 |
| | $ | 1,051,962 |
|
| Capital contributions from parent | — |
| | 13,300 |
| | 8,630 |
|
| Balance at end of period | 1,073,892 |
| | 1,073,892 |
| | 1,060,592 |
|
| Retained earnings: | | | | | |
| Balance at beginning of period | 349,419 |
| | 267,432 |
| | 268,209 |
|
| Net income | 170,553 |
| | 172,987 |
| | 136,723 |
|
| Cash distributions to parent | (234,000 | ) | | (91,000 | ) | | (137,500 | ) |
| Balance at end of period | 285,972 |
| | 349,419 |
| | 267,432 |
|
| Accumulated other comprehensive income (loss): | | | | | |
| Balance at beginning of period | 152 |
| | 214 |
| | 276 |
|
| Cash flow hedges: | | | | | |
| Reclassification of unrecognized gain into earnings | (62 | ) | | (62 | ) | | (62 | ) |
| Balance at end of period | 90 |
| | 152 |
| | 214 |
|
| Total owner’s equity | $ | 1,359,954 |
| | $ | 1,423,463 |
| | $ | 1,328,238 |
|
NORTHWEST PIPELINE
GPSTATEMENT OF COMPREHENSIVE INCOME
(Thousands of Dollars)
| | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
Net income | | $ | 152,813 | | | $ | 149,527 | | | $ | 153,651 | |
Cash flow hedges: | | | | | | | | | | | | |
Amortization of cash flow hedges | | | (62 | ) | | | (62 | ) | | | (62 | ) |
| | | | | | | | | | | | |
Total comprehensive income | | $ | 152,751 | | | $ | 149,465 | | | $ | 153,589 | |
| | | | | | | | | | | | |
See accompanying notes.
NORTHWEST PIPELINE GP
LLC
(Thousands of Dollars)
| | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
OPERATING ACTIVITIES: | | | | | | | | | | | | |
Net income | | $ | 152,813 | | | $ | 149,527 | | | $ | 153,651 | |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | | | | | | | | | | | |
Depreciation | | | 90,486 | | | | 87,915 | | | | 86,373 | |
Regulatory credits | | | (1,023 | ) | | | (1,662 | ) | | | (2,403 | ) |
(Gain) loss on sale of property, plant and equipment | | | 6 | | | | — | | | | (508 | ) |
Amortization of deferred charges and credits | | | 1,491 | | | | 2,293 | | | | 5,050 | |
Allowance for equity funds used during construction | | | (1,438 | ) | | | (1,947 | ) | | | (1,996 | ) |
Changes in current assets and liabilities: | | | | | | | | | | | | |
Trade accounts receivable | | | 270 | | | | 1,927 | | | | (326 | ) |
Affiliated receivables, including income taxes | | | (132 | ) | | | 2,396 | | | | (3,284 | ) |
Exchange gas due from others | | | 402 | | | | 1,262 | | | | 2,623 | |
Materials and supplies | | | 1,231 | | | | (1,759 | ) | | | (143 | ) |
Other current assets | | | (54 | ) | | | 826 | | | | 1,744 | |
Trade accounts payable | | | (597 | ) | | | (559 | ) | | | (828 | ) |
Affiliated payable, including income taxes | | | (1,462 | ) | | | (13,026 | ) | | | 350 | |
Exchange gas due to others | | | (402 | ) | | | (1,262 | ) | | | (2,623 | ) |
Other accrued liabilities | | | 827 | | | | 985 | | | | (4,860 | ) |
Changes in noncurrent assets and liabilities: | | | | | | | | | | | | |
Deferred charges | | | (2,829 | ) | | | (5,865 | ) | | | (3,362 | ) |
Other deferred credits | | | 4,769 | | | | 8,148 | | | | 5,340 | |
| | | | | | | | | | | | |
Net cash provided by operating activities | | | 244,358 | | | | 229,199 | | | | 234,798 | |
| | | | | | | | | | | | |
FINANCING ACTIVITIES: | | | | | | | | | | | | |
Proceeds from issuance of long-term debt | | | — | | | | 8,000 | | | | — | |
Retirement of long-term debt | | | — | | | | (8,000 | ) | | | — | |
Capital contributions from parent | | | 5,100 | | | | 19,000 | | | | 49,180 | |
Distributions paid | | | (127,000 | ) | | | (191,450 | ) | | | (135,000 | ) |
Other | | | 657 | | | | (1,209 | ) | | | 2,212 | |
| | | | | | | | | | | | |
Net cash used in financing activities | | | (121,243 | ) | | | (173,659 | ) | | | (83,608 | ) |
| | | | | | | | | | | | |
INVESTING ACTIVITIES: | | | | | | | | | | | | |
Property, plant and equipment - | | | | | | | | | | | | |
Capital expenditures* | | | (115,111 | ) | | | (120,236 | ) | | | (152,580 | ) |
Proceeds from sales | | | (993 | ) | | | 3,913 | | | | 2,234 | |
Repayments from (advances to) affiliates | | | (6,979 | ) | | | 60,386 | | | | (787 | ) |
| | | | | | | | | | | | |
Net cash used in investing activities | | | (123,083 | ) | | | (55,937 | ) | | | (151,133 | ) |
| | | | | | | | | | | | |
NET INCREASE (DECREASE) IN CASH | | | 32 | | | | (397 | ) | | | 57 | |
CASH AT BEGINNING OF PERIOD | | | 5 | | | | 402 | | | | 345 | |
| | | | | | | | | | | | |
CASH AT END OF PERIOD | | $ | 37 | | | $ | 5 | | | $ | 402 | |
| | | | | | | | | | | | |
| | | |
| | | | | | | | | | | | |
| | | |
* Increases to property, plant and equipment | | $ | (115,677 | ) | | $ | (117,629 | ) | | $ | (156,576 | ) |
Changes in related accounts payable and accrued liabilities | | | 566 | | | | (2,607 | ) | | | 3,996 | |
| | | | | | | | | | | | |
Capital expenditures | | $ | (115,111 | ) | | $ | (120,236 | ) | | $ | (152,580 | ) |
| | | | | | | | | | | | |
Supplemental disclosures of non-cash transactions: | | | | | | | | | | | | |
Adjustment to owner’s equity for benefit plans correction | | $ | — | | | $ | — | | | $ | (4,402 | ) |
Loans to affiliate reclassified to equity | | | — | | | | — | | | | 66,764 | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| OPERATING ACTIVITIES: | | | | | |
| Net income | $ | 170,553 |
| | $ | 172,987 |
| | $ | 136,723 |
|
| Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | | | | |
| Depreciation | 99,138 |
| | 96,109 |
| | 93,419 |
|
| Regulatory debits (credits) | 1,487 |
| | 921 |
| | (494 | ) |
| Gain on sale of property, plant and equipment | (70 | ) | | — |
| | — |
|
| Amortization of deferred charges and credits | 894 |
| | 1,720 |
| | 1,578 |
|
| Allowance for equity funds used during construction | (391 | ) | | (945 | ) | | (1,564 | ) |
| Changes in current assets and liabilities: | | | | | |
| Trade and other accounts receivable | 395 |
| | 2,133 |
| | (8,291 | ) |
| Affiliated receivables | 38,388 |
| | (38,744 | ) | | 567 |
|
| Exchange gas due from others | (1,433 | ) | | 153 |
| | (1,262 | ) |
| Materials and supplies | 203 |
| | (132 | ) | | 351 |
|
| Other current assets | (1,326 | ) | | (202 | ) | | 116 |
|
| Trade accounts payable | (4,958 | ) | | (212 | ) | | 6,305 |
|
| Affiliated payables | 2,007 |
| | 224 |
| | 2,100 |
|
| Exchange gas due to others | 2,179 |
| | (153 | ) | | 1,262 |
|
| Other accrued liabilities | (3,095 | ) | | 3,885 |
| | 169 |
|
| Changes in noncurrent assets and liabilities: | | | | | |
| Deferred charges | (2,087 | ) | | (7,448 | ) | | (4,015 | ) |
| Noncurrent liabilities | 11,000 |
| | 9,819 |
| | 5,442 |
|
| Net cash provided by operating activities | 312,884 |
| | 240,115 |
| | 232,406 |
|
| FINANCING ACTIVITIES: | | | | | |
| Capital contributions from parent | — |
| | 13,300 |
| | 8,630 |
|
| Cash distributions to parent | (234,000 | ) | | (91,000 | ) | | (137,500 | ) |
| Other | (622 | ) | | (1,318 | ) | | 329 |
|
| Net cash used in financing activities | (234,622 | ) | | (79,018 | ) | | (128,541 | ) |
| INVESTING ACTIVITIES: | | | | | |
| Property, plant and equipment: | | | | | |
| Capital expenditures, net of equity AFUDC* | (79,413 | ) | | (83,317 | ) | | (136,168 | ) |
| Contributions and advances for construction costs | 3,056 |
| | 6,326 |
| | 1,838 |
|
| Proceeds from sales | 5,728 |
| | 5,756 |
| | 7,843 |
|
| Repayments from (advances to) affiliates, net | (15,886 | ) | | (89,846 | ) | | 22,702 |
|
| Proceeds from insurance | 8,274 |
| | — |
| | — |
|
| Net cash used in investing activities | (78,241 | ) | | (161,081 | ) | | (103,785 | ) |
| NET INCREASE IN CASH | 21 |
| | 16 |
| | 80 |
|
| CASH AT BEGINNING OF PERIOD | 133 |
| | 117 |
| | 37 |
|
| CASH AT END OF PERIOD | $ | 154 |
| | $ | 133 |
| | $ | 117 |
|
| ____________________________________ | | | | | |
| * Increases to property, plant and equipment | $ | (71,207 | ) | | $ | (88,123 | ) | | $ | (133,998 | ) |
| Changes in related accounts payable and accrued liabilities | (8,206 | ) | | 4,806 |
| | (2,170 | ) |
| Capital expenditures, net of equity AFUDC | $ | (79,413 | ) | | $ | (83,317 | ) | | $ | (136,168 | ) |
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Corporate Structure and Control
At December 31, 2014, Northwest Pipeline
GPLLC (Northwest) is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams)
. On February 2, 2015, WPZ was merged into Access Midstream Partners, L.P. (ACMP),
another publicly traded limited partnership consolidated by Williams. ACMP was the surviving partnership and
was subsequently renamed Williams Partners L.P. At February 25, 2015, Williams holds an approximate
7260 percent interest in
WPZ,the merged partnership, comprised of an approximate
7058 percent limited partner interest and all of
WPZ’sthe 2 percent general partner interest.
Northwest
is not an employer.has no employees. Services are provided to Northwest by
Northwest Pipeline Services LLC (NPS), a Williams’ affiliate.Williams and its affiliates. Northwest reimburses
NPSWilliams and its affiliates 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.”
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.
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
89 for further discussion.)
Basis of Presentation
Reclassifications within the investing activities of the Statement of Cash Flows, between Capital expenditures, net of equity AFUDC* and Contributions and advances for construction costs of $6.3 million and $1.8 million for the years ended December 31, 2013 and 2012, respectively, have been made to correct the 2013 and 2012 financial statements to conform to the 2014 presentation.
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.
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
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
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
interruptible transportation services and storage injection and withdrawal services, are recognized
whenbased on volumes of natural gas
is scheduled
to be deliveredfor delivery at the agreed upon delivery point or
when thebased on volumes of natural gas
is scheduled
to be injectedfor injection or
withdrawnwithdrawal 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.customers is included in the exchange gas offset. 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.SNL Financial “Bidweek Index - Spot Rates.” 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,
2011,2014, we had no
such rate refund liabilities.
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. We believe that
any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates.
Property, Plant, and Equipment
Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost.
We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated
depreciation.depreciation; certain other gains or losses are recorded in operating income.
We provide for depreciation
usingunder the
straight-linecomposite (group) method at
straight-line FERC prescribed rates
including negative salvage (costthat are applied to the cost of
removal)the group for transmission and storage facilities.
Depreciation of general plant is provided on a group basis at straight-line rates.Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component
(net cost of removal) that we currently collect in rates.
Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31,
2011, 20102014, 2013 and
20092012 are as follows:
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
| | | | | | | | | | | | |
Category of Property | | | | | | | | | |
Storage Facilities | | | 0.15 | % | | | — | | | | 2.23 | % |
Transmission Facilities | | | 0.15 | % | | | — | | | | 6.67 | % |
|
| | | | | | | |
| Category of Property | | | | | |
| Storage Facilities | 1.60 | % | | — |
| | 2.76% |
| Transmission Facilities | 2.80 | % | | — |
| | 6.97% |
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
createdcreates a
consistent 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.
The FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory
asset with the offsetting credit recorded to a regulatory credit on the accompanying Statement of Income.asset.
We recorded regulatory
debits totaling $1.5 million in 2014 and $0.9 million in 2013 and regulatory credits totaling
$1.0$0.5 million in
2011, $1.7 million in 2010, and $2.4 million in 20092012 in the accompanying Statement of
Comprehensive Income. These
debits and credits relate primarily to the levelized depreciation
adjustment for the Evergreen Project discussed above.
The accompanying Balance Sheet reflects the related regulatory assets of $33.5 million at December 31, 2011, and $32.5 million at December 31, 2010. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.We record an asset and a liability equal toand increase the basis in the underlying asset for the present value of each expected future asset retirement obligation (ARO). The ARO at the time the liability is initially incurred, typically when the asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets.acquired or constructed. 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
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
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
gross regulatory asset balances associated with ARO as of December 31, 2014 and 2013 were $63.7 million and $57.9 million, respectively. The regulatory asset is
beingexpected to be fully recovered through the net negative salvage component of depreciation included in our
rates, and is being amortized to expense consistent withrates; as such, the
amounts collected in rates. The regulatory asset balances as of December 31, 2011 and 2010 were $45.9 million and $40.5 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.The negative salvage component of accumulated depreciation ($37.960.2 million and $33.6$51.2 million at December 31, 20112014 and 2010,2013, respectively) washas been 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.
asset.
Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
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. The 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.was $0.2 million for 2014, $0.5 million for 2013 and $0.7 million for 2012. The equity funds portion of AFUDC is includedwas $0.4 million, $0.9 million and $1.6 million for 2014, 2013, and 2012, respectively. Both are reflected in Other Income – net.(Income) and Other Expenses
. The composite rate used to capitalize AFUDC was approximately 9 percent 10 percent,for 2014, 2013, and 9 percent, for 2011, 2010 and 2009, respectively. Equity AFUDC of $1.4 million, $1.9 million and $2.0 million for 2011, 2010 and 2009, respectively, is reflected in Other Income—net.Regulatory Allowance for Equity Funds Used During Construction2012.
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.
We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under
ourthe WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in
usWPZ is not available to us.
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.
There was a minimal reserve at December 31, 2014 and 2013.
NOTES TO FINANCIAL STATEMENTS
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.
Pension and Other Postretirement Benefits
We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 5 for further discussion.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us, and thus paid by us, is based on our share of net periodic benefit cost.
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances
changeschange that affect the previous assumptions or estimates.
Cash Flows from Operating Activities and Cash Equivalents
We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents.
Cash payments for interest, net of interest capitalized, were $44.5 million in 2014 and $44.6 million in 20112013 and 20102012.
Accounting Standards Issued But Not Yet Adopted
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09 establishing Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and $44.5requires significantly enhanced revenue disclosures. The standard is effective for annual reporting periods beginning after December 15, 2016, and interim periods within the reporting period. Accordingly, we will adopt this standard in the first quarter of 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is not permitted. We continue to evaluate both the impact of this new standard on our financial statements and the transition method we will utilize for adoption.
2. RATE AND REGULATORY MATTERS
Rate Case Settlement Filing
On April 26, 2012, the FERC unconditionally approved Northwest’s Stipulation and Settlement Agreement (Settlement) filed on March 15, 2012. The Settlement specified an annual cost of service of $466.5 million
and established a new general system firm transportation rate of $0.44 per dekatherm, a 7.4 percent increase over the previous rate. New rates became effective January 1, 2013, and will remain in
2009.2.effect for a minimum of 3 years and a maximum of 5 years.
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
3. CONTINGENT LIABILITIES AND COMMITMENTS
Legal Proceedings
We are a party to legal, administrative, and regulatory proceedings arising in the ordinary course of business.
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
Federal Energy Regulatory Commission (FERC)FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates.
WeAs a result, we believe that compliance with applicable environmental requirements is not likely to have a material adverse 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,
lubricating oil leaks or spills, and
excess pipe coating released to the environment. In addition, heavy metals have been identified at these sites due to the former use of mercury
contamination at certain natural gas metering sites.containing meters and paint and welding rods containing lead, cadmium, and arsenic. 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
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
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 upAs of December 31, 2014, all of our meter stations have been remediated to Washington’s current environmental standards. In addition, assessments have been completed at all thirteen compressor stations in Washington. Remediation has been completed at nine of these compressor stations. On the basis of the findings to date, we estimate that environmental assessment and remediation costs will total approximately $7.8 million, measured on an undiscounted basis, and are expected to be incurred through 2020. At December 31, 2011,2014 and 2013, we had accrued liabilities totaling approximately $6.8$7.8 million and $8.7 million, respectively, for these costs which are expected to be incurred through 2017.costs. 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,In May 2012, 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 delayedcompleted designation of new eight-hour ozone non-attainment areas underareas. Based on the published designations, no Northwest facilities are located within the non-attainment areas. At this time, it is unknown whether future state regulatory actions associated with implementation of the 2008 standards untilozone standard will impact our operations and increase the reconsideration is complete. cost of additions to property, plant and equipment. Until any additional state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet any such new regulation.
In January 2010,December 2014, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. On September 22, 2011,The EPA is anticipated to finalize any revisions in late 2015. Revisions to the EPA announced that it was proceeding with required actions to implement the 2008 ozone standard and area designations. Designation of new eight-hour ozone non-attainment areas are expected toNAAQS will result in additional federal and state regulatory actions that will likelymay impact our operations and increaseoperations. As a result, the cost of additions to property, plant, and equipment. Until such non-attainment areas are designated, weequipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.
On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO2 NAAQS, and thus, designated all areas of the country as “unclassifiable/attainment.” Also, at that time, the EPA noted its plan to deploy an expanded NO2 monitoring network beginning in 2013. However, on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO2 NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO2 standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this 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 capital costs in the range of $6 million to $9 million through 2013, the compliance date.
In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. Given the uncertainty associated with the implementation of the new standard and the broad range of actions we could be required to take to meet the standard, we have not estimated the cost of additions that may be required to meet this new regulation.
Safety Matters
Pipeline Integrity RegulationsWe 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 through 2012 and associated remediation will be primarily capital in nature and range between $30 million and $35 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.
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
Various other proceedings are pending against us and are considered incidental to our operations.
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third-parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss.
Other Commitments
We have commitments for construction and acquisition of property, plant and equipment of approximately $10.4 million at December 31, 2011.
Cash Distributions to Partners
During January 2012, we declared and paid equity distributions of $28 million to WPZ.
3.
4. DEBT, FINANCING ARRANGEMENTS, AND LEASES
Long-term debt, presented net of unamortized discount, consists of the following:
| | | | | | | | |
| | | December 31, | |
| | | 2011 | | | 2010 | |
| | | (Thousands of Dollars) | |
5.95% senior unsecured notes due 2017 | | $ | 184,662 | | | $ | 184,599 | |
6.05% senior unsecured notes due 2018 | | | 249,573 | | | | 249,506 | |
7% senior unsecured notes due 2016 | | | 174,754 | | | | 174,698 | |
7.125% unsecured debentures due 2025 | | | 84,842 | | | | 84,831 | |
| | | | | | | | |
Total long-term debt | | $ | 693,831 | | | $ | 693,634 | |
| | | | | | | | |
|
| | | | | | | |
| | December 31, |
| | 2014 | | 2013 |
| | (Thousands of Dollars) |
| 5.95% senior unsecured notes due 2017 | $ | 184,854 |
| | $ | 184,790 |
|
| 6.05% senior unsecured notes due 2018 | 249,771 |
| | 249,705 |
|
| 7% senior unsecured notes due 2016 | 174,919 |
| | 174,864 |
|
| 7.125% unsecured debentures due 2025 | 84,876 |
| | 84,865 |
|
| Total long-term debt | $ | 694,420 |
| | $ | 694,224 |
|
As of December 31,
2011,2014, cumulative maturities of outstanding long-term debt (at face value) for the next five years
total $175.0 million, all of which is attributable to the seven percent senior unsecured notes, due June 15, 2016.are as follows:
|
| | | |
| | (Thousands of Dollars) |
| 2016: 7% senior unsecured notes | $ | 175,000 |
|
| 2017: 5.95% senior unsecured notes | 185,000 |
|
| 2018: 6.05% senior unsecured notes | 250,000 |
|
| Total | $ | 610,000 |
|
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 of the 7% senior unsecured notes due 2016, 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, recorded in accumulatedAccumulated other comprehensive income, that is being amortized to reduce interest expense over the life of the related debt.NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
Restrictive Debt Covenants
At December 31,
2011,2014, 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.
Credit Facility
In June 2011,
On December 1, 2014, we, entered into a $2 billion five-year senior unsecured revolving credit facility agreement (Credit Facility)along with WPZ, and Transcontinental Gas Pipe Line, Company, LLC, (Transco), the lenders named therein, and an administrative agent, entered into Amendment No. 1 and Consent to the First Amended and Restated Credit Agreement, dated as co-borrowers.of July 31, 2013. The amendment provided the consent of the lenders for this credit agreement replacedto continue for ACMP upon consummation of the merger with WPZ and the termination of ACMP’s existing $1.75 billioncredit agreement. In addition, the amendment provided the consent that certain existing liens and guarantees of indebtedness of ACMP that were terminated in connection with the merger would not become liens and guarantees of indebtedness under this credit agreement. At December 31, 2014, no letters of credit were issued and no loans were outstanding under this credit facility. On February 2, 2015, this credit facility agreement that was scheduled to expireterminated in connection with the merger.
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
On February
17, 2013. The2, 2015, we, along with WPZ, Transco, the lenders named therein, and an administrative agent, entered into the Second Amended and Restated Credit
Facility may, under certain conditions, be increasedAgreement with aggregate commitments available of $3.5 billion, with up to an additional
$400 million.$500 million increase in aggregate commitments available under certain circumstances. The
fullmaturity date of the facility is February 2, 2020. However, the co-borrowers may request an extension of the maturity date for an additional one-year period, up to two times, to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to an aggregate amount of
$150 million, subject to available capacity under the credit facility,
isand letters of credit commitments available to
WPZ.WPZ of $1.125 billion. We
mayare able to borrow up to
$400$500 million under
the Credit Facilitythis credit facility to the extent not otherwise utilized by
WPZ and Transco.the other co-borrowers.
Under the credit facility, WPZ is required to maintain a ratio of debt to EBITDA (each as defined in the credit facility) that must be no greater than
55.0 to
1.1.00. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions
for a total aggregate purchase price equal to or greater than $50 million hashave been executed, WPZ is required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1.00. For us, the ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent.
AtMeasured as of December 31,
2011,2014, we are in compliance with
thesethis financial
covenants.Each time funds are borrowed, the borrowercovenant.
Various covenants may
choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The borrower is required to pay a commitment fee (currently 0.25 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The credit facility contains various covenants that limit, among other things, a borrower’s and its
respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default,
make investmentsenter into certain restrictive agreements, and allow any material change in the nature of its business.
The credit facility includes customary events of default.
If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower
under the credit facility agreement and exercise other rights and remedies.
Total letter
Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 1/2 of 1 percent, and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b), and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit capacityfacility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.
WPZ participates in a commercial paper program, and WPZ management considers amounts outstanding under this program to be a reduction of available
to WPZcapacity under the credit
facility is $1.3 billion.facility. On February 2, 2015, WPZ amended and restated the commercial paper program for the merger and to allow a maximum outstanding of $3 billion of unsecured commercial paper notes. At December 31,
2011, no letters of credit have been issued and the full $4002014, WPZ had $798 million
under the credit facility was available to us.in outstanding commercial paper.
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.
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
| | | | |
| | | (Thousands of Dollars) | |
2012 | | $ | 2,428 | |
2013 | | | 2,428 | |
2014 | | | 2,428 | |
2015 | | | 2,455 | |
2016 | | | 2,481 | |
| | | | |
Total | | $ | 12,220 | |
| | | | |
|
| | | |
| | (Thousands of Dollars) |
| 2015 | $ | 2,581 |
|
| 2016 | 2,608 |
|
| 2017 | 2,634 |
|
| 2018 | 2,661 |
|
| 2019 | 2,687 |
|
| Total | $ | 13,171 |
|
Operating lease rental expense, net of sublease revenues, amounted to
$2.4$2.5 million,
$2.3 million, and $2.2 million
for 2014, 2013, and
$3.6 million for 2011, 2010 and 2009,2012, respectively.
4.
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.
(See Note 7 for further discussion.)
Pension and Other Postretirement Benefit Plans
Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan, and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension
expensecost charged to us by Williams was
$5.7$4.2 million in
2011, $6.12014, $7.8 million in
20102013, and
$7.5$7.3 million in
2009.2012.
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 expenseDuring 2014 and 2013, we received credits from Williams related to retiree health care and life insurance benefits of $4.3 million and $1.7 million, respectively. The credit in 2012 was
recognized in 2011, 2010, or 2009,minimal. These credits were recorded as
such costs are not currently being recovered in our rates. (See Note 8.)regulatory liabilities.
Defined Contribution Plan
Included in compensation expense is $2.0 million for 2014 and 2013 and $2.5 million for 2012 that Williams charged us
compensation expense of $2.4 million in 2011, $2.2 million in 2010, and $2.2 million in 2009 for
Williams’ company matching contributions to this plan.
Employee Stock-Based Compensation Plan Information
The Williams Companies, Inc. 2007 Incentive Plan, as amended and restated 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 nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved.
Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the
options.awards. We are also billed for our proportionate share of
both Williams Gas Pipeline Company, LLC’s (WGP)Williams’ and
Williams’other affiliates’ stock-based compensation expense through various allocation processes.
Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31,
2011, 20102014, 2013 and
20092012 was $1.2 million,
$1.4$1.2 million and
$1.3$1.6 million, respectively, excluding amounts allocated from
WGP, WPZ and Williams.
NOTES TO FINANCIAL STATEMENTS
5.
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 and advances to affiliate—The carrying amounts approximate fair value, because of the short-term nature of these items approximates their fair value.instruments. Long-term debt— – The disclosed fair value of our publicly traded long-term debt, which we consider as a level 2 measurement, is valueddetermined by a market approach using broker quoted indicative period-end traded bond market prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The carrying amount and estimated fair value of our long-term debt, including current maturities, were $693.8$694.4 million and $826.3$766.5 million, respectively, at December 31, 2011,2014, and $693.6$694.2 million and $796.1$806.1 million, respectively, at December 31, 2010.2013.6.
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:
| | | | | | | | | | | | |
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | | | 2009 | |
| | | (Thousands of Dollars) | |
Puget Sound Energy, Inc. | | $ | 99,116 | | | $ | 95,564 | | | $ | 94,508 | |
Northwest Natural Gas Co. | | | 47,322 | | | | 48,022 | | | | 49,256 | |
|
| | | | | | | | | | | |
| | Years Ended December 31, |
| | 2014 | | 2013 | | 2012 |
| | (Thousands of Dollars) |
| Puget Sound Energy, Inc. | $ | 113,398 |
| | $ | 110,111 |
| | $ | 100,799 |
|
| Northwest Natural Gas Company | 50,631 |
| | 51,085 |
| | 42,297 |
|
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
We are a participant in WPZ’s cash management program. At December 31, 20112014 and 2010,2013, the advances due to us by WPZ totaled approximately $52.0$135.1 million and $45.0$119.2 million, respectively. These advances are represented by demand notes.notes and are classified as Current Assets in the accompanying Balance Sheet. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month, which was approximately 0.01 percent at December 31, 2011.2014. The interest income from these advances was minimal during the years ended December 31, 2011, 2010,2014, 2013, and 2009.2012. Such interest income is included in “Other Income – net: Interest income – Affiliated”Other (Income) and Other Expenses: Miscellaneous other expenses, net on the accompanying Statement of Comprehensive Income.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, for the years ended December 31, 2011, 2010, and 2009, were $35.4 million, $34.1 million, and $36.0 million, respectively. These expenses are included in “General and administrative expense” on the accompanying Statement of Income. Management considers the cost of these services to be reasonable.
Northwest has
We have no employees. Services necessary to operate our business are provided to us by an affiliate, NPS. In return, weWilliams and certain affiliates of Williams. We reimburse NPSWilliams and its affiliates for all direct and indirect expenses it incursincurred or payments it makesmade (including salary, bonus, incentive compensation, pension and other benefits) in connection with these services. ForEmployees of Williams also provide general administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three factor formula, which considers revenues; property, plant, and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $102.4 million, $106.7 million, and $113.0 million in the years ended December 31, 2011, 20102014, 2013, and 2009, we were billed $62.6 million, $60.6 million, and $60.1 million, respectively.2012, respectively, for these services. Such expenses are primarily included in “GeneralGeneral and administrative”administrative and “OperationOperation and maintenance”maintenance expenses on the accompanying Statement of Comprehensive Income. In 2014 and 2013, we incurred reimbursable costs of $27.3 million and $89.8 million, respectively, due from Williams Field Services related to the construction of a natural gas liquids pipeline, of which $0.5 million and $38.6 million was outstanding at December 31, 2014 and 2013, respectively.
NOTES TO FINANCIAL STATEMENTS
During
the periods presented, our revenues include transportation transactions2014, 2013, and
rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities, for the years ended December 31, 2011, 2010, and 2009, were $24.7 million, $6.8 million, and $9.9 million, 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 for the year ended December 31, 2009, is included in “Operation and maintenance expense” on the accompanying Statement of Income. The lease was terminated on August 1, 2009.
During 2011, 2010, and 2009,2012, we declared and paid equitycash distributions to our parent of $127.0$234.0 million, $191.5$91.0 million, and $135.0$137.5 million, respectively. During January 2012,2015, we declared and paid equitycash distributions of $28.0$58.0 million to our parent.
During
2011, 2010,2013, and
2009,2012, we received contributions of
$5.1 million, $19.0$13.3 million, and
$49.2$8.6 million from our parent to fund a portion of our expenditures for additions to property, plant, and equipment.
In January 2012, our parent authorized an additional $1.2 million capital contribution to us to fund a portion of our expenditures for additions to property, plant and equipment.No contributions were received in 2014.
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.
7.
8. ASSET RETIREMENT OBLIGATIONS
Our accrued asset retirement 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.
During
20112014 and
2010,2013, our overall asset retirement obligation changed as follows (in thousands):
| | | | | | | | |
| | | 2011 | | | 2010 | |
Beginning balance | | $ | 65,155 | | | $ | 86,749 | |
Accretion | | | 5,162 | | | | 6,058 | |
New obligations | | | 2,257 | | | | 27 | |
Changes in estimates of existing obligations (1) | | | 8,116 | | | | (27,679 | ) |
Property Dispositions & Settlements | | | (377 | ) | | | — | |
| | | | | | | | |
Ending balance | | $ | 80,313 | | | $ | 65,155 | |
| | | | | | | | |
|
| | | | | | | |
| | 2014 | | 2013 |
| Beginning balance | $ | 60,753 |
| | $ | 67,640 |
|
| Accretion | 5,602 |
| | 5,708 |
|
| New obligations | 157 |
| | 51 |
|
| Changes in estimates of existing obligations (1) | 28,171 |
| | (12,577 | ) |
| Property Dispositions & Settlements | (5 | ) | | (69 | ) |
| Ending balance | $ | 94,678 |
| | $ | 60,753 |
|
| |
| (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 increase in 2014 is primarily attributed to increases in current estimates for removal costs and inflation rate, and a decrease in the discount rate. The decrease in 2013 is primarily attributed to increases in the discount rate and the remaining life of the applicable property. |
NORTHWEST PIPELINE GP
NOTES TO FINANCIAL STATEMENTS
8.
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 Exchange gas offset and other.Prepayments and other. Current regulatory liabilities are included in other accrued liabilities and noncurrent regulatory liabilities are included in deferred credits and other noncurrent liabilities.Exchange gas offset. 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, 20112014 and 2010: | | | | | | | | |
| | | 2011 | | | 2010 | |
| | | (Thousands of Dollars) | |
Current regulatory assets: | | | | | | | | |
Environmental costs | | $ | 2,200 | | | $ | 2,200 | |
Fuel recovery | | | 78 | | | | 45 | |
| | | | | | | | |
Total current regulatory assets | | | 2,278 | | | | 2,245 | |
| | | | | | | | |
Noncurrent regulatory assets: | | | | | | | | |
Environmental costs | | | 1,117 | | | | 3,317 | |
Grossed-up deferred taxes on equity funds used during construction | | | 17,034 | | | | 17,458 | |
Levelized depreciation | | | 33,485 | | | | 32,463 | |
Asset retirement obligations, net | | | 7,969 | | | | 6,938 | |
| | | | | | | | |
Total noncurrent regulatory assets | | | 59,605 | | | | 60,176 | |
| | | | | | | | |
Total regulatory assets | | $ | 61,883 | | | $ | 62,421 | |
| | | | | | | | |
Current regulatory liabilities: | | | | | | | | |
Fuel recovery | | $ | 3,562 | | | $ | 731 | |
| | | | | | | | |
Noncurrent regulatory liabilities: | | | | | | | | |
Postretirement benefits | | | 17,386 | | | | 16,264 | |
| | | | | | | | |
Total regulatory liabilities | | $ | 20,948 | | | $ | 16,995 | |
| | | | | | | | |
2013:
NORTHWEST PIPELINE LLC
NOTES TO FINANCIAL STATEMENTS
|
| | | | | | | |
| | 2014 | | 2013 |
| | (Thousands of Dollars) |
| Current regulatory assets: | | | |
| Environmental costs | $ | 1,300 |
| | $ | 1,300 |
|
| Levelized depreciation | 1,999 |
| | — |
|
| Total current regulatory assets | 3,299 |
| | 1,300 |
|
| Noncurrent regulatory assets: | | | |
| Environmental costs | 2,109 |
| | 2,843 |
|
| Grossed-up deferred taxes on equity funds used during construction | 14,567 |
| | 15,325 |
|
| Levelized depreciation | 29,775 |
| | 33,261 |
|
| Asset retirement obligations, net | 3,472 |
| | 6,712 |
|
| Total noncurrent regulatory assets | 49,923 |
| | 58,141 |
|
| Total regulatory assets | $ | 53,222 |
| | $ | 59,441 |
|
| Current regulatory liabilities: | | | |
| Fuel recovery | $ | 4,004 |
| | $ | 638 |
|
| Noncurrent regulatory liabilities: | | | |
| Postretirement benefits | 23,375 |
| | 19,047 |
|
| Other | — |
| | 205 |
|
| Total noncurrent regulatory liabilities | 23,375 |
| | 19,252 |
|
| Total regulatory liabilities | $ | 27,379 |
| | $ | 19,890 |
|
The significant regulatory assets and liabilities include:
Environmental CostsWe 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 regulatory asset. The regulatory asset is being amortized to expense consistent with amounts collected in rates. Fuel RecoveryThese 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 ConstructionThe 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 DepreciationLevelized 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 inas a FERC approved regulatory asset or liability and is extinguishedeliminated over the levelization period.
NORTHWEST PIPELINE GPGrossed-Up Deferred Taxes on Equity Funds Used During ConstructionNOTES TO FINANCIAL STATEMENTS 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. All amounts were generated during the period that we were a taxable entity. 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.
Asset Retirement ObligationsWe record an This regulatory asset and a liability equalbalance is established to the present valueoffset depreciation of each expected future ARO. Thethe ARO asset is depreciated in a manner consistent with the expected future abandonment of the underlying physical assets. We measureand changes in the ARO liability due to the 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.time. The regulatory asset is beingexpected to be fully recovered through the net negative salvage component of depreciation included in our rates,rates; as such, the negative salvage component of accumulated depreciation has been reclassified and is being amortizednetted against the amount of the ARO regulatory asset.
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 expense consistent withbe recovered or refunded by changing the amounts collectedfuel reimbursement factor in rates.subsequent fuel filings. Postretirement BenefitsWe 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.
The following is a summary of unaudited quarterly financial data for
20112014 and
2010: | | | | | | | | | | | | | | | | |
| | | Quarter of 2011 | |
| | | First | | | Second | | | Third | | | Fourth | |
| | | (Thousands of Dollars) | |
Operating revenues | | $ | 109,919 | | | $ | 106,576 | | | $ | 107,216 | | | $ | 110,773 | |
Operating income | | | 51,232 | | | | 46,596 | | | | 46,082 | | | | 53,319 | |
Net income | | | 39,683 | | | | 35,379 | | | | 35,241 | | | | 42,510 | |
| |
| | | 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 | |
2013:
|
| | | | | | | | | | | | | | | |
| | Quarter of 2014 |
| | First | | Second | | Third | | Fourth |
| | (Thousands of Dollars) |
| Operating revenues | $ | 119,085 |
|
| $ | 114,644 |
|
| $ | 116,249 |
|
| $ | 120,072 |
|
| Operating income | 57,025 |
|
| 48,903 |
|
| 56,003 |
|
| 54,231 |
|
| Net income | 45,483 |
|
| 37,656 |
|
| 44,488 |
|
| 42,926 |
|
|
| | | | | | | | | | | | | | | |
| | Quarter of 2013 |
| | First | | Second | | Third | | Fourth |
| | (Thousands of Dollars) |
| Operating revenues | $ | 118,734 |
| | $ | 113,853 |
| | $ | 115,971 |
| | $ | 121,103 |
|
| Operating income | 57,192 |
| | 51,142 |
| | 52,767 |
| | 56,833 |
|
| Net income | 45,638 |
| | 40,025 |
| | 41,832 |
| | 45,492 |
|
|
| |
| Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
|
| |
| Item 9A. | Controls and Procedures |
Disclosure Controls and Procedures
Our management, including our Senior Vice President
— West and our Vice President and
Treasurer,Chief Accounting Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a—15(e) and 15d—15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within
Northwestthe company 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
— West and our Vice President and
Treasurer.Chief Accounting Officer. Based upon that evaluation, our Senior Vice President
— West and our Vice President and
TreasurerChief Accounting Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Management’s Annual Report on
Changes in Internal Control over Financial Reporting
See report set forth in Item 8, “Financial Statements and Supplementary Data.”
Fourth Quarter 2011 Changes in Internal Controls
There have been no changes during the fourth quarter of 20112014 that have materially affected, or are reasonably likely to materially affect, our Internal ControlsControl over Financial Reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a – 15(f) and 15d – 15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to our management 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 — West and our Vice President and Chief Accounting Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, as of December 31, 2014, 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 management’s report in this annual report.
|
| |
| Item 9B. | OTHER INFORMATION |
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:
| | | | | | | | |
| | | 2011 | | | 2010 | |
| | | (Thousands of Dollars) | |
Audit fees | | $ | 800 | | | $ | 791 | |
Audit related fees | | | — | | | | — | |
Tax fees | | | — | | | | — | |
All other fees | | | — | | | | — | |
| | | | | | | | |
| | $ | 800 | | | $ | 791 | |
| | | | | | | | |
|
| | | | | | | |
| | 2014 | | 2013 |
| | (Thousands of Dollars) |
| Audit fees | $ | 737 |
| | $ | 752 |
|
| Audit related fees | — |
| | — |
|
| Tax fees | — |
| | — |
|
| All other fees | — |
| | — |
|
| | $ | 737 |
| | $ | 752 |
|
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
and FERC 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 WPZ’s general partner have been set forth in WPZ’s
20112014 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and
on WPZ’s website at http://
williamslp.com under the heading “Investors – SEC Filings.”investor.williams.com.
|
| |
| Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| | |
| |
| | | Page
Reference to
2011 2014 Form
10-K |
| |
(a) 1. and 2. Northwest Pipeline GPLLC financials | |
| | |
| Index | |
Index
| | | | |
Covered by reports of independent auditors: | | | | |
Statement of Income for the Years Ended December 31, 2011, 2010, and 2009
| | | 29 | |
Balance Sheet at December 31, 2011 and 2010
| | | 30 | |
Statement of Owners’ Equity for the Years Ended December 31, 2011, 2010, and 2009
| | | 32 | |
| |
| | 33 | |
| |
| |
| |
| |
| |
| | 34 | |
| |
| | 35 | |
Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2011 and 2010
| | | 50 | |
Not covered by reports of independent auditors: | |
| | |
| | | 48 | |
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.
(a) 2. Financial Statement Schedules
NORTHWEST PIPELINE GP
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
(Thousands
|
| | |
Exhibit | | Description |
| |
2(a)2 | | Certificate of Conversion of Northwest Pipeline CorporationGP (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007)July 3, 2013 (File No. 001-07414)) and incorporated herein by reference. |
| |
3(a) | | Statement |
| 3.1 | | Certificate of Partnership ExistenceFormation of Northwest Pipeline GPLLC (Exhibit 2.2 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference. |
| |
| 3.2 | | Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our report on Form 8-K, filed October 2, 2007)July 3, 2013 (File No. 001-07414)) 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)4.1 | | Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our Registration Statement on Form S-3, filed September 14, 1995)1995 (File No. 033-62639)) and incorporated herein by reference. |
| |
4(b)4.2 | | Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our report on Form 8-K, filed June 23, 2006)2006 (File No. 001-07414)) and incorporated herein by reference. |
| |
4(c)4.3 | | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York, as trustee, relating to $185 million aggregate principal amount of 5.95% Senior Notes due 2017 (Exhibit 4.1 to our report on Form 8-K, filed April 6, 2007)2007 (File No. 001-07414)) and incorporated herein by reference. |
| |
4(d)4.4 | | Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trusteetrustee, relating to $250 million aggregate principal amount of 6.05% Senior Notes due 2018 (Exhibit 4.1 to our report on Form 8-K, filed May 23, 2008)2008 (File No. 001-07414)) and incorporated herein by reference. |
| |
10(a)10.1 | | 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)2008 (File No. 001-07414)) and incorporated herein by reference. |
| |
10(b)10.2 | | Contribution, Conveyance and AssumptionAssignment Agreement dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC,February 13, 2013, by and between Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC HoldingsServices, LLC and Williams Pipeline Services Company WPC-I, LLC, effective January 1, 2013 (Exhibit 10.210(b) to our report on Form 8-K,10-K, filed January 30, 2008)February 27, 2013 (File No. 001-07414)) and incorporated herein by reference. |
| | |
| |
10(c)10.3 | | First Amended & Restated Credit Agreement, dated as of June 3, 2011,July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline GP,LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed as Exhibit 10.1(Exhibit 10 to Williams Partners L.P.’s No. 1-32599, quarterly reportQuarterly Report on Form 10-Q, filed on August 4, 2011)July 31, 2013 (File No. 001-32599)) and incorporated herein by reference. |
| | |
31(a)*10.4 | | Amendment No. 1 and Consent to First Amended & Restated Credit Agreement, dated as of December 1, 2014, by and among Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s report on form 8-K, filed December 4, 2014 (File No. 0001-32599)) and incorporated herein by reference. |
| | |
| 10.5 | | Second Amended and Restated Credit Agreement, dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s report on Form 8-K, filed on February 3, 2015 (File No. 001-34831)) and incorporated herein by reference. |
| | |
| 31.1* | | 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)*31.2* | | 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)*32** | | 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. |
| |
101.INS** | | XBRL Instance Document. |
| |
101.I SCH **101.SCH* | | XBRL Taxonomy Extension Schema. |
| |
101.CAL** | | XBRL Taxonomy Extension Calculation Linkbase. |
| |
|
| | |
| 101.DEF* | | XBRL Taxonomy Definition Linkbase |
| |
101.LAB** | | XBRL Taxonomy Extension Label Linkbase. |
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101.PRE** | | XBRL Taxonomy Extension Presentation Linkbase. |
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)
|
| (Registrant) |
| |
| By | | /s/ R. Rand Clark/s/ Jeffrey P. Heinrichs |
| | R. Rand Clark
| Jeffrey P. Heinrichs |
| | | Controller |
Date: February 27, 201225, 2015
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.
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Signature | | Title |
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/s/ Randall L. Barnard
| | |
| /s/ Walter J. Bennett | | Senior Vice President – West and Management Committee Member (Principal Executive Officer) |
Randall L. Barnard
Walter J. Bennett | |
| | (Principal Executive Officer) |
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/s/ Richard D. Rodekohr Ted T. Timmermans | | Vice President and Treasurer |
Richard D. Rodekohr
| | Chief Accounting Officer (Principal Financial Officer) |
| Ted T. Timmermans | |
/s/ Allison G. Bridges
| | Vice President |
Allison G. Bridges
| | |
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/s/ R. Rand Clark Jeffrey P. Heinrichs | | Controller (Principal Accounting Officer) |
R. Rand Clark
Jeffrey P. Heinrichs | | |
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/s/ Donald R. Chappel | | Management Committee Member |
Donald R. Chappel | | |
Date: February 27, 201225, 2015
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Exhibit | | Description |
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2(a)2 | | Certificate of Conversion of Northwest Pipeline CorporationGP (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007)July 3, 2013 (File No. 001-07414)) and incorporated herein by reference. |
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3(a) | | Statement |
| 3.1 | | Certificate of Partnership ExistenceFormation of Northwest Pipeline GPLLC (Exhibit 2.2 to our report on Form 8-K, filed July 3, 2013 (File No. 001-07414)) and incorporated herein by reference. |
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| 3.2 | | Operating Agreement of Northwest Pipeline LLC (Exhibit 3.1 to our report on Form 8-K, filed October 2, 2007)July 3, 2013 (File No. 001-07414)) and incorporated herein by reference. |
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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. |
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4(a)4.1 | | Senior Indenture, dated as of November 30, 1995 between Northwest Pipeline Corporation and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures due 2025 (Exhibit 4.1 to our Registration Statement on Form S-3, filed September 14, 1995)1995 (File No. 033-62639)) and incorporated herein by reference. |
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4(b)4.2 | | Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., relating to Northwest Pipeline’s $175 million aggregate principal amount of 7.0% Senior Notes due 2016 (Exhibit 4.1 to our report on Form 8-K, filed June 23, 2006)2006 (File No. 001-07414)) and incorporated herein by reference. |
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4(c)4.3 | | Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York, as trustee, relating to $185 million aggregate principal amount of 5.95% Senior Notes due 2017 (Exhibit 4.1 to our report on Form 8-K, filed April 6, 2007)2007 (File No. 001-07414)) and incorporated herein by reference. |
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4(d)4.4 | | Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trusteetrustee, relating to $250 million aggregate principal amount of 6.05% Senior Notes due 2018 (Exhibit 4.1 to our report on Form 8-K, filed May 23, 2008)2008 (File No. 001-07414)) and incorporated herein by reference. |
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10(a)10.1 | | 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)2008 (File No. 001-07414)) and incorporated herein by reference. |
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10(b) | | Contribution, Conveyance and Assumption |
| 10.2 | | Assignment Agreement dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC,February 13, 2013, by and between Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC HoldingsServices, LLC and Williams Pipeline Services Company
WPC-I, LLC, effective January 1, 2013 (Exhibit 10.210(b) to our report on Form 8-K,10-K, filed January 30, 2008)February 27, 2013 (File No. 001-07414)) and incorporated herein by reference. |
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10(c) | | |
| 10.3 | | First Amended & Restated Credit Agreement, dated as of June 3, 2011,July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline GP,LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed as Exhibit 10.1(Exhibit 10 to Williams Partners L.P.’s No. 1-32599, quarterly reportQuarterly Report on Form 10-Q, filed on August 4, 2011)July 31, 2013 (File No. 001-32599)) and incorporated herein by reference. |
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31(a)*10.4 | | Amendment No. 1 and Consent to First Amended & Restated Credit Agreement, dated as of December 1, 2014, by and among Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s report on form 8-K, filed December 4, 2014 (File No. 0001-32599)) and incorporated herein by reference. |
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| 10.5 | | Second Amended and Restated Credit Agreement, dated as of February 2, 2015, between Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.), Northwest Pipeline LLC, and Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to Williams Partners L.P.’s report on Form 8-K, filed on February 3, 2015 (File No. 001-34831)) and incorporated herein by reference. |
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| 31.1* | | Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. |
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31(b)*31.2* | | Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002. |
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32(a)*32** | | 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. |
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101.INS** | | XBRL Instance Document. |
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101.I SCH **101.SCH* | | XBRL Taxonomy Extension Schema. |
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101.CAL** | | XBRL Taxonomy Extension Calculation Linkbase. |
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| 101.DEF* | | XBRL Taxonomy Definition Linkbase |
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101.LAB** | | XBRL Taxonomy Extension Label Linkbase. |
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101.PRE** | | XBRL Taxonomy Extension Presentation Linkbase. |