Item 1A.
Risk Factors
FORWARD-LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations.
All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:
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amounts and nature of future capital expenditures;
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expansion and growth of our business and operations;
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business strategy;
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cash flow from operations;
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seasonality of certain business segments; and
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natural gas liquids and gas prices and demand.
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The reader should carefully consider the risk factors discussed below in addition to the other information in this annual report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units and the trading price of our common units could decline and unitholders could lose all or part of their investment. Many of the factors that could adversely affect our business, results of operations and financial condition are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
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We may not have sufficient cash from operations to enable us to pay the minimum distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
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Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect new sources of natural gas supply, which is dependent on factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.
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Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.
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Our processing, fractionation and storage businesses could be affected by any decrease in NGL prices or a change in NGL prices relative to the price of natural gas.
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We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
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If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
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We do not own all of the interests in Wamsutter, the Conway fractionator or Discovery, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.
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Our results of storage and fractionation operations are dependent upon the demand for propane and other NGLs. A substantial decrease in this demand could adversely affect our business and operating results.
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Discovery and Wamsutter may reduce their cash distributions to us in some situations.
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Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators, which could have a material adverse effect on our business and operating results.
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Discovery’s interstate tariff rates and terms and conditions are subject to changes in policy by federal regulators, which could have a material adverse effect on our business and operating results.
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We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
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Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
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Williams’ public indentures and our credit facility contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
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Our future financial and operating flexibility may be adversely affected by restrictions in our indentures and by our leverage.
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We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make payments on our debt obligations and distributions on our common units.
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Common units held by Williams eligible for future sale may have adverse effects on the price of our common units.
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Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interests with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.
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Even if unitholders are dissatisfied, they have little ability to remove our general partner without its consent.
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 include the following:
Risks Inherent in Our Business
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the prices we obtain for our services;
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the prices of, level of production of, and demand for, natural gas and NGLs;
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the volumes of natural gas we gather, transport, process and treat and the volumes of NGLs we fractionate and store;
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the level of our operating costs, including payments to our general partner; and
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prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:
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the level of capital expenditures we make;
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the restrictions contained in Williams’ indentures, our indentures and credit facility and our debt service requirements;
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the cost of acquisitions, if any;
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fluctuations in our working capital needs;
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our ability to borrow for working capital or other purposes;
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the amount, if any, of cash reserves established by our general partner;
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the amount of cash that each of Discovery and Wamsutter distributes to us; and
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reimbursement payments to us by, and credits from, Williams under the omnibus agreement.
Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.
Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect new sources of natural gas supply, which is dependent on factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.
Our and Discovery’s pipelines receive natural gas directly from offshore producers. Our Four Corners gathering system receives natural gas directly from producers in the San Juan Basin, and our Wamsutter gathering system receives natural gas directly from producers in the Washakie Basin. The production from existing wells connected to these pipelines and our Four Corners and Wamsutter gathering systems will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. We do not produce an aggregate reserve report on a regular basis or regularly obtain or update independent reserve evaluations. The amount of natural gas reserves underlying these wells may be less than we anticipate, and the rate at which production will decline from these reserves may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on these pipelines and gathering systems and the utilization rate of our natural gas processing plants and fractionators, we must continually connect new supplies of natural gas. The primary factors affecting our ability to connect new supplies of natural gas and attract new customers to our pipelines include: (1) the level of successful drilling activity near these assets; (2) our ability to compete for volumes from successful new wells and existing wells connected to third parties; and (3) our ability to successfully complete lateral expansion projects to connect to new wells.
We do not have any current significant lateral expansion projects planned and Discovery has only one significant lateral expansion project under construction. Discovery signed definitive agreements with Chevron Corporation, Royal Dutch Shell plc, and StatoilHydro ASA to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. In October 2007, Chevron announced that it will face delays because of metallurgical problems discovered in the facility’s mooring shackles and that it does not expect first production to commence until the third quarter of 2009.
The level of drilling activity in the fields served by our pipelines and gathering systems is dependent on economic and business factors beyond our control. The primary factors that impact drilling decisions are oil and natural gas prices. A sustained decline in oil and natural gas prices could result in a decrease in exploration and development activities in these fields, which would lead to reduced throughput levels on our pipelines and gathering system. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability of qualified personnel and equipment, the quality of drilling prospects in the area and regulatory changes. Because of these factors, even if new oil or natural gas reserves are discovered in areas served by our pipelines and gathering system, producers may choose not to develop those reserves. If we were not able to connect new supplies of natural gas to replace the natural decline in volumes from existing wells, due to reductions in drilling activity, competition, or difficulties in completing lateral expansion projects to connect to new supplies of natural gas, throughput on our pipelines and gathering systems and the utilization rates of our natural gas processing plants and fractionators would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.
Lower natural gas and oil prices could result in a decline in the production of natural gas and NGLs resulting in reduced throughput on our pipelines and gathering systems. Any such decline would reduce the amount of NGLs we fractionate and store, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
In general terms, the prices of natural gas, NGLs and other hydrocarbon products fluctuate in response to changes in supply, changes in demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:
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worldwide economic conditions;
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weather conditions and seasonal trends;
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the levels of domestic production and consumer demand;
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the availability of imported natural gas and NGLs;
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the availability of transportation systems with adequate capacity;
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the price and availability of alternative fuels;
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the effect of energy conservation measures;
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the nature and extent of governmental regulation and taxation; and
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the anticipated future prices of natural gas, NGLs and other commodities.
Our processing, fractionation and storage businesses could be affected by any decrease in NGL prices or a change in NGL prices relative to the price of natural gas.
Lower NGL prices would reduce the revenues we generate from the sale of NGLs for our own account. Under certain gas processing contracts, referred to as “percent-of-liquids” and “keep whole” contracts, we receive NGLs removed from the natural gas stream during processing and may then choose to either fractionate and sell the NGLs or to sell the NGLs directly. In addition, product optimization at our Conway fractionator generally leaves us with excess propane, an NGL, which we sell. We also sell excess storage volumes resulting from measurement variances at our Conway storage facilities.
The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us and our customers to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices reduce the volumes of NGLs removed at their processing plants, which would reduce their margins. Finally, higher natural gas prices relative to NGL prices could also reduce volumes of gas processed generally, reducing the volumes of mixed NGLs available for fractionation.
We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
We rely on a limited number of customers for a significant portion of our revenues. One producer customer, ConocoPhillips, accounted for approximately 53% of the Gathering and Processing - West segment’s total gathered volumes for the year ended December 31, 2007. With respect to total revenues, a subsidiary of Williams, to which we sell substantially all of the NGLs we retain under our keep-whole and percent-of-liquids processing contracts, accounted for approximately 49% of our total revenues for the year ended December 31, 2007. However, all of the NGLs sold to the subsidiary of Williams are derived from our processing of producer customers’ natural gas. For the year ended December 31, 2007, ConocoPhillips accounted for 24% of the Gathering and Processing - West segment’s total revenues.
Six producer customers, BP, Anadarko Petroleum Corporation, Devon Energy Corporation, Marathon Oil Corporation, Samson Resources Company, and EnCana Corporation, accounted for approximately 92% of Wamsutter’s total gathered volumes for the year ended December 31, 2007. With respect to total revenues, a subsidiary of Williams, to which Wamsutter sells substantially all of the NGLs it retains under its keep-whole contracts, accounted for approximately 56% of Wamsutter’s total revenues for the year ended December 31, 2007. Although this revenue is identified as sales to a subsidiary of Williams, all of the NGLs sold to the subsidiary of Williams are derived from Wamsutter’s processing of producer customers’ natural gas.
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. In addition, we are subject to active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status and that represent 19% of the total MMBtu gathered by our Four Corners system. All of the agreements
in evergreen status represent approximately 33% of our total MMBtu gathered revenues for the year ended December 31, 2007. The negotiations may not result in any extended commitments from these customers or may result in extended commitments on less favorable terms. The loss of all or even a portion of the revenues from natural gas or NGLs, as applicable, supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to unitholders, unless we are able to acquire comparable volumes from other sources.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. For example, MAPL delivers its customers’ mixed NGLs to our Conway fractionator and provides access to multiple end markets for NGL products of our storage customers. If MAPL were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to store or deliver NGL products and we would be unable to receive deliveries of mixed NGLs at our Conway fractionator. This would have an immediate adverse impact on our ability to enter into short-term storage contracts and our ability to fractionate sufficient volumes of mixed NGLs at Conway.
MAPL also provides the only current liquids pipeline access to multiple end markets for NGL products that are recovered from our Four Corners and Wamsutter processing plants. If MAPL were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, we would be unable to deliver a substantial portion of the NGLs recovered at our Four Corners and Wamsutter processing plants. This would have an immediate impact on our ability to sell or deliver NGL products recovered at our Four Corners and Wamsutter processing plants. In addition, the five pipeline systems that move natural gas to end markets from the San Juan Basin connected to our Four Corners treating and processing facilities, including the El Paso Natural Gas, Transwestern, Williams’ Northwest Pipeline, Public Service Company of New Mexico and Southern Trails systems. The four pipeline systems that move natural gas to end markets from our Wamsutter processing facilities are the Colorado Interstate Gas, Wyoming Interstate Gas, Southern Star Central Gas Pipeline and Rockies Express systems. Some of these natural gas pipeline systems have minimal excess capacity. If any of these pipeline systems were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers may be unable to deliver natural gas to end markets. This could reduce the volumes of natural gas processed or treated at our Four Corners treating and processing facilities and our Wamsutter processing facilities. Either of such events could materially and adversely affect our business results of operations, financial condition and ability to make distributions to unitholders.
Any temporary or permanent interruption in operations on third party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to unitholders.
We do not own all of the interests in Wamsutter, the Conway fractionator or Discovery, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.
Because we do not wholly own Wamsutter, the Conway fractionator or Discovery, we may have limited flexibility to control the operation of, dispose of, encumber or receive cash from these assets. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Our results of storage and fractionation operations are dependent upon the demand for propane and other NGLs. A substantial decrease in this demand could adversely affect our business and operating results.
Our Conway storage and fractionation operations are impacted by demand for propane more than any other NGLs. Conway, Kansas is one of the two major trading hubs for propane and other NGLs in the continental United States. Demand for propane at Conway is principally driven by demand for its use as a heating fuel. However, propane is also used as an engine and industrial fuel and as a petrochemical feedstock in the production of ethylene and propylene. Demand for propane as a heating fuel is significantly affected by weather conditions and the availability of alternative heating fuels such as natural gas. Weather-related demand is subject to normal seasonal fluctuations, but an unusually warm winter could cause demand for propane as a heating fuel to decline significantly. Demand for other NGLs, which include ethane, butane, isobutane and natural gasoline, could be adversely impacted by general economic conditions, a reduction in demand by customers for plastics and other end products made from NGLs, an increase in competition from petroleum-based products, government regulations or other reasons. Any decline in demand for propane or other NGLs could cause a reduction in demand for our Conway storage and fractionation services.
When prices for the future delivery of propane and other NGLs that we store at our Conway facilities fall below current prices, customers are less likely to store these products, which could reduce our storage revenues. This market condition is commonly referred to as “backwardation.” When the market for propane and other NGLs is in backwardation, the demand for storage capacity at our Conway facilities may decrease. While this would not impact our long-term capacity leases, customers could become less likely to enter into short-term storage contracts.
Discovery and Wamsutter may reduce their cash distributions to us in some situations.
Discovery’s and Wamsutter’s limited liability company agreements provide that they will distribute their available cash to their members on a quarterly basis. Discovery’s available cash includes cash on hand less any reserves that may be appropriate for operating its business and Wamsutter’s available cash includes cash generated from Wamsutter’s business less any reserves that may be appropriate for operating its business. As a result, reserves established by Discovery and Wamsutter, including those for working capital, will reduce the amount of available cash. The amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the members of its management committee representing a majority-in-interest in such entity. The amount of Wamsutter’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the affirmative vote of the Class B member’s representative on the management committee.
We own a 60% interest in Discovery. In addition, to the extent Discovery requires working capital in excess of applicable reserves, we must make working capital advances to Discovery of up to the amount of Discovery’s two most recent prior quarterly distributions of available cash, but Discovery must repay any such advances before it can make future distributions to its members. As a result, the repayment of advances could reduce the amount of cash distributions we would otherwise receive from Discovery.
Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators, which could have a material adverse effect on our business and operating results.
The FERC, pursuant to the Natural Gas Act, regulates Discovery’s interstate pipeline transportation service. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. The FERC could lower the tariff rates Discovery is currently permitted to charge its customers, on its own initiative, or as a result of challenges raised by Discovery’s customers or third parties and the FERC could require refunds of amounts collected under rates which it finds unlawful. An adverse decision by the FERC in approving Discovery’s regulated rates or on the rehearing of the proposed settlement discussed below could adversely affect our cash flows. Although the FERC generally does not regulate the natural gas gathering operations of Discovery under the Natural Gas Act, federal regulation influences the parties that gather natural gas on the Discovery gas gathering system.
On November 16, 2007, Discovery filed a settlement, which is uncontested by its active shippers, in lieu of a general rate case filing. If approved by the FERC, the settlement would resolve numerous rate and other issues and achieve rate certainty on Discovery for at least five years. On February 5, 2008, the FERC approved the settlement but the order is subject to rehearing and therefore not final or effective. If the settlement does not become effective and if Discovery files a rate case, all aspects of Discovery’s cost of service and design of its rates could be reviewed.
Please read “Business and Properties - FERC Regulation - Discovery” for further information.
Discovery’s interstate tariff rates and terms and conditions are subject to changes in policy by federal regulators, which could have a material adverse effect on our business and operating results.
FERC standards of conduct govern how interstate pipelines communicate and do business with their marketing affiliates. Among other things, the standards of conduct require that interstate pipelines do not operate their systems to preferentially benefit their marketing affiliates. The current rule, which is an interim rule, applies only to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on that natural gas transmission provider’s pipeline. Therefore, the interim rule does not currently apply to Discovery. FERC has issued a notice of proposed rulemaking that proposes permanent standards of conduct. We have no way to predict with certainty the scope of FERC’s permanent rules on the standards of conduct. However, we do not believe that Discovery’s natural gas pipeline will be affected by any action taken previously or in the future on these matters materially differently than other natural gas service providers with whom Discovery competes.
In 2005, the FERC indicated that it will permit pipelines to include in cost-of-service an income tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income (See FERC Regulation). If the settlement discussed above does not become final and instead Discovery files a general rate case, under the FERC’s current policy Discovery would be required to prove that it is permitted to include an income tax allowance in its cost of service. These aspects of Discovery’s rates could also be reviewed if the FERC or a shipper initiated a complaint proceeding. If the FERC were to disallow a substantial portion of Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates.
In 2006, the FERC issued a new order addressing rates on one of the interstate oil pipelines of SFPP, L.P. The FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly-traded partnerships. It noted that the tax deferral features of a publicly-traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a “tax savings.” The FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, the FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly-traded partnership’s cash flow exceeded taxable income. In February 2007, SFPP, L.P. asked the FERC to reconsider this ruling. The rehearing request is still pending before the FERC. The ultimate outcome of this proceeding is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost-of-service. If the FERC does not approve the settlement discussed above and instead Discovery files a general rate case, Discovery may be subject to potential adjustment of its equity rate-of-return that underlies its recourse rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders.
In July 2007, the FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of publicly traded master limited partnerships (MLPs) in the proxy group for purposes of calculating returns on equity under the discounted cash flow analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion. The FERC’s proposed policy statement is subject to change. Therefore, we cannot predict the scope of the final policy statement. If the settlement discussed above does not become final and Discovery files a general rate case instead, and
Discovery has not completed the hearing phase of the rate case as of the date the FERC issues its final policy statement, as currently proposed the final policy statement would apply to Discovery’s rate case.
We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
Williams operates all of our assets, other than:
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the Carbonate Trend pipeline, which is operated by Chevron;
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most of our Four Corners field compression, excluding major turbine compressor stations, which are operated by Exterran Holdings, Inc. (Exterran); and
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Exterran operates two compression units in the Wamsutter gathering field, and Devon Energy Corporation (Devon) owns and operates four compressor stations on the Eastern part of the Wamsutter gathering system that compress its gas.
We have a limited ability to control our operations or the associated costs of these operations. The success of these operations is therefore dependent upon a number of factors that are outside our control, including the competence and financial resources of the operators.
We also rely on Williams for 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 as an operator and on Williams’ outsourcing relationships, our reliance on Chevron, Exterran and Devon and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Williams’ public indentures and our credit facility contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
Williams’ public indentures contain covenants that restrict Williams’ 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’ ability to comply with the covenants contained in its debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ ability to comply with these covenants may be impaired.
Our credit facility contains various covenants that, among other things, limit our ability to incur indebtedness, grant certain liens to support indebtedness, merge, or sell substantially all of our assets. 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 the covenants contained in the credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”
Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. Any future down grading of a Williams’ credit rating would likely also result in a down grading of our credit rating. A down grading of a Williams’ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
Our future financial and operating flexibility may be adversely affected by restrictions in our indentures and by our leverage.
In December 2007, we borrowed $250.0 million under the term loan portion of our new $450.0 million five-year senior unsecured credit facility. Our total outstanding long-term debt as of December 31, 2007 was $1.0 billion, representing approximately 86% of our total book capitalization.
Our debt service obligations and restrictive covenants in the indentures governing our senior unsecured notes could have important consequences. For example, they could:
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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;
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impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;
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adversely affect our ability to pay cash distributions to unitholders;
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diminish our ability to withstand a downturn in our business or the economy generally;
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require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes; limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
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place us at a competitive disadvantage compared to our competitors that have proportionately less debt.
Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. If we are unable to meet our debt service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our senior notes.
Discovery and Wamsutter are not prohibited from incurring indebtedness, which may affect our ability to make distributions to unitholders.
Discovery and Wamsutter are not prohibited by the terms of their respective limited liability company agreements from incurring indebtedness. If Discovery or Wamsutter was to incur significant amounts of indebtedness, such occurrence may inhibit their ability to make distributions to us. An inability by Discovery or Wamsutter to make distributions to us would materially and adversely affect our ability to make distributions to unitholders because we expect distributions we receive from Discovery and Wamsutter to represent a significant portion of the cash we distribute to unitholders.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do.
Discovery competes with other natural gas gathering and transportation and processing facilities and other NGL fractionation facilities located in south Louisiana, offshore in the Gulf of Mexico and along the Gulf
Coast, including the Manta Ray/Nautilus systems, the Trunkline pipeline and the Venice Gathering System and the processing and fractionation facilities that are connected to these pipelines.
Our Conway fractionation facility competes for volumes of mixed NGLs with fractionators located in each of Hutchinson, Kansas, Medford, Oklahoma, and Bushton, Kansas owned by ONEOK Partners, L.P., the other joint owners of the Conway fractionation facility and, to a lesser extent, with fractionation facilities on the Gulf Coast. Our Conway storage facilities compete with ONEOK-owned storage facilities in Bushton, Kansas and in Conway, Kansas, an NCRA-owned facility in Conway, Kansas, a ONEOK-owned facility in Hutchinson, Kansas and an Enterprise Products Partners-owned facility in Hutchinson, Kansas and, to a lesser extent, with storage facilities on the Gulf Coast and in Canada.
Four Corners competes with other natural gas gathering, processing and treating facilities in the San Juan Basin, including Enterprise, Red Cedar and TEPPCO. In addition, our customers who are significant producers of gas or consumers of NGLs may develop their own gathering, processing, treating, fractionation and storage facilities in lieu of using ours.
Wamsutter competes with other natural gas gathering and processing facilities in the Washakie Basin, including Anadarko’s Patrick Draw and Red Desert facilities and Colorado Interstate Gas’ Rawlins facility. In addition, customers who are significant producers of gas or consumers of NGLs may develop their own gathering and processing facilities in lieu of using Wamsutter’s gathering and processing facility.
Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Pipeline integrity programs and repairs may impose significant costs and liabilities on us.
In December 2003, the DOT issued a final rule requiring pipeline operators to develop integrity management programs for gas transportation pipelines located in “high consequence areas” where a leak or rupture could do the most harm. The final rule requires operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002. The final rule became effective on January 14, 2004. In response to this new Department of Transportation rule, we have initiated pipeline integrity testing programs that are intended to assess pipeline integrity. In addition, we have voluntarily initiated a testing program to assess the integrity of the brine pipelines of our Conway storage facilities and replaced three sections of brine systems at a cost of $0.7 million. We have completed most of the testing and expect to complete the remainder of the testing in 2008.
The State of New Mexico recently enacted rule changes that permit the pressure in gathering pipelines to be reduced below atmospheric levels. In response to these rule changes, Four Corners may reduce the pressures in its gathering lines below atmospheric levels. With Four Corners’ concurrence, producers may also reduce pressures below atmospheric levels prior to delivery to Four Corners. All of the gathering lines owned by Four Corners in the San Juan Basin are made of steel. Reduced pressures below atmospheric levels may introduce increasing amounts of oxygen into those pipelines, which could cause an acceleration of corrosion.
We may not be able to grow or effectively manage our growth.
A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon a number of factors, some of which we can control and some of which we cannot. These factors include our ability to:
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identify businesses engaged in managing, operating or owning pipeline, processing, fractionation and storage assets, or other midstream assets for acquisitions, joint ventures and construction projects;
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control costs associated with acquisitions, joint ventures or construction projects;
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consummate acquisitions or joint ventures and complete construction projects;
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integrate any acquired or constructed business or assets successfully with our existing operations and into our operating and financial systems and controls;
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hire, train and retain qualified personnel to manage and operate our growing business; and
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obtain required financing for our existing and new operations.
A failure to achieve any of these factors would adversely affect our ability to achieve anticipated growth in the level of cash flows or realize anticipated benefits. Furthermore, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay.
We may acquire new facilities or expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects could result in the incurrence of indebtedness and additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders. Further, if we issue additional common units in connection with future acquisitions, unitholders’ interest in us will be diluted and distributions to unitholders may be reduced.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are operational risks associated with the gathering, transporting, processing and treating of natural gas and the fractionation and storage of NGLs, including:
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hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters and acts of terrorism;
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damages to pipelines and pipeline blockages;
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leakage of natural gas (including sour gas), NGLs, brine or industrial chemicals;
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collapse of NGL storage caverns;
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operator error;
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pollution;
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fires, explosions and blowouts;
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risks related to truck and rail loading and unloading; and
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risks related to operating in a marine environment.
Any of these or any other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of life, property damage, damage to the environment or other significant exposure to liability. For example, in 2004 we experienced a temporary interruption of service on one of
Discovery’s pipelines due to an influx of seawater while connecting a new lateral. In addition, on November 28, 2007, we had a fire at our Ignacio gas processing plant that resulted in a significant disruption of our operations associated with that plant. Although the plant is now operating, the fire destroyed much of the plant’s spare parts inventory. Consequently, there could be additional disruptions of operations due to failure of parts for which the acquisition of replacements requires significant lead time.
Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs to retain necessary land use. We obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. Our loss 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 and financial condition and our ability to make cash distributions to unitholders. For example, portions of our Four Corners gathering system are located on Native American rights-of-way. Four Corners is currently in discussions with the Jicarilla Apache Nation regarding rights-of-way that expired at the end of 2006 for a segment of the gathering system which flows less than 10% of Four Corners’ gathered volumes. We continue to operate these assets under a special business license that expires February 29, 2008. Based upon current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the Jicarilla Apache Nation lands represents approximately $20.0 million to $30.0 million of Four Corners’ annual gathering and processing revenue less related product costs.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.
The risk of substantial environmental costs and liabilities is inherent in natural gas gathering, transportation, processing and treating, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to stringent federal, state and local laws and regulations relating to protection of the public and the environment. These laws include, for example:
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the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions;
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the Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (CWA) and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;
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the Federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and
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the Federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.
Various governmental authorities, including the EPA have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we gather, transport, process, fractionate and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury. Private parties, including the owners of properties through which our pipeline and gathering systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third party hydrocarbon storage and processing operations and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary.
For example, the KDHE regulates the storage of NGLs and natural gas in the state of Kansas. This agency also regulates the construction, operation and closure of brine ponds associated with such storage facilities. In response to a significant incident at a third party facility, the KDHE promulgated more stringent regulations regarding safety and integrity of brine ponds and storage caverns. Additionally, incidents similar to the incident at a third party facility that prompted the recent KDHE regulations could prompt the issuance of even stricter regulations. In addition, the Department of Environmental Quality in Wyoming has created a new emissions rule for sites with production greater than 3,000 million cubic feet per day. Wamsutter has reacted by installing methanol injectors at these sites. This requirement increases the well connect costs for new wells in Wyoming.
There is increasing pressure in New Mexico from environmental groups and area residents to reduce the noise from midstream operations through regulatory means. If these groups are successful, we may have to make capital expenditures to muffle noise from our facilities or to ensure adequate barriers or distance to mitigate noise concerns.
Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits.
Also, new environmental laws and regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are examples of greenhouse gases. In response to such studies, the U.S. Congress is actively considering legislation and more than a dozen states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap and trade programs. Moreover, the U.S. Supreme Court only recently held in a case, Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.
The natural gas gathering operations in the San Juan Basin and Washakie Basin may be subjected to regulation by the state of New Mexico, which could negatively affect our revenues and cash flows.
The New Mexico state legislature has previously called for hearings to take place to examine the regulation of natural gas gathering systems in the state. It is unclear if further discussions or hearings in New Mexico will occur, but they could result in gathering regulation that could affect the fees that we could collect for gathering services. This type of regulation could adversely impact our revenues and cash flow.
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future.
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosure, the relationships between companies and their independent auditors, and retirement plan practices. 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 or the Securities Exchange Commission (SEC) could enact new accounting standards that might impact how we would be 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, financial condition and ability to make cash distributions to unitholders.
Terrorist attacks have resulted in increased costs, and attacks directed at our facilities or those of our suppliers and customers could disrupt our operations.
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the United States government has issued warnings that energy assets may be the future target of terrorist organizations. These developments have subjected our operations to increased risks and costs. The long-term impact that terrorist attacks and the threat of terrorist attacks may have on our industry in general, and on us in particular, is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways. In addition, uncertainty regarding future attacks and war cause global energy markets to become more volatile. Any terrorist attack on our facilities or those of our suppliers or customers could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Changes in the insurance markets attributable to terrorists’ attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in financial markets as a result of terrorism or war could also affect our ability to raise capital.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
Risks Inherent in an Investment in Us
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make payments on our debt obligations and distributions on our common units.
We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. Williams Partners L.P. has no significant assets other than the ownership interests in its subsidiaries. As a result, our ability to make required payments on our debt obligations and distributions on our common units depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, applicable state partnership and limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the occurrence of a change of control or make distributions on our common units, we may be required to adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to
make distributions on our common units. We cannot assure you that we will be able to borrow funds to make distributions on our common units.
Common units held by Williams eligible for future sale may have adverse effects on the price of our common units.
As of February 19, 2008, Williams held 11,613,527 common units, including common units issued to Williams as partial consideration for the Wamsutter Ownership Interests representing a 21.6% limited partnership interest in us. Williams may, from time to time, sell all or a portion of its common units or subordinated units. Sales of substantial amounts of their common units or subordinated units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.
Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties, and they favor their own interests to the detriment of our unitholders.
Williams owns and controls our general partner, and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and its affiliates, including Williams Pipeline Partners’ general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner and Williams Pipeline Partners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us. Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to ours;
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our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
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our general partner determines the amount and timing of any capital expenditures, and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner in respect of the incentive distribution rights;
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in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions;
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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
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our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
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generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
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provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
Common unitholders are bound by the provisions in the partnership agreement, including the provisions discussed above.
Even if unitholders are dissatisfied, they have little ability to remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 662/3% of all outstanding common units is required to remove our general partner.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their member interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. This effectively permits a change of control without your consent. In addition, pursuant to the omnibus agreement with Williams, any new owner of the general partner would be required to change our name so that there would be no further reference to Williams.
Increases in interest rates may cause the market price of our common units to decline.
In recent years, the United States credit markets experienced 50-year record lows in interest rates. If the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation risk. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt to make acquisitions or for other purposes.
We may issue additional common units without unitholder approval, which would dilute unitholder ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available to pay distributions on each unit may decrease;
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the ratio of taxable income to distribution may decrease;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
Affiliates of our general partner, including Williams and Williams Pipeline Partners, are not limited in their ability to compete with us. Williams is also not obligated to offer us the opportunity to acquire additional assets or businesses from it, which could limit our commercial activities or our ability to grow. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner, and these persons will also owe fiduciary duties to those entities.
While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams is in the natural gas business and is not restricted from competing with us. Williams and its affiliates, including Williams Pipeline Partners, which trades on the NYSE under the symbol “WMZ,” may compete with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct such assets. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner and will owe fiduciary duties to those entities as well as our unitholders and us.
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, non-affiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would not longer be subject to the reporting requirements of the Securities Exchange Act of 1934.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.
Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.
We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Transactions, and Director Independence.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, if the unitholders become dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35%, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to federal, state or local entity-level taxation. For example, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions to unitholders would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner
that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. Legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred.
We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
An IRS contest of the federal income tax positions we take may adversely impact the market for the common units, and the costs of any contest will reduce our cash available for distribution to our unitholders and our general partner.
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for the common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
Unitholders will be required to pay taxes on their share of our income even if unitholders do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
The tax gain or loss on the disposition of the common units could be different than expected.
If a unitholder sells its common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income it was allocated for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than its original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash it received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in Colorado, Kansas, Louisiana, New Mexico, Alabama and Wyoming. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder’s
responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.
The sale or exchange of 50% or more of the total interest in our capital and profits during any 12-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 3.
Item 3.
Legal Proceedings
The information called for by this item is provided in Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements of this report, which information is incorporated into this Item 3 by reference.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information, Holders and Distributions
Our common units are listed on the New York Stock Exchange under the symbol “WPZ.” At the close of business on February 20, 2007, there were 52,774,728 common units outstanding, held by approximately 16,089 holders, including common units held in street name and by affiliates of Williams.
On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.
The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the New York Stock Exchange Composite Transactions Tape, and quarterly cash distributions paid to our unitholders.
(a)
Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its 2% general partner interest and incentive distribution rights that totaled $1.8 million and $10.7 million for the 2006 and 2007 periods, respectively. On February 19, 2008, the 7,000,000 outstanding subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis. Subordinated units participated in all of the cash distributions for the periods indicated above.
(b)
Class B units participated in the fourth quarter 2006 and first quarter 2007 cash distributions. Class B units were outstanding between December 13, 2006 and May 21, 2007, on which date all 6,805,492 Class B units converted into common units on a one-for-one basis.
Distributions of Available Cash
Within 45 days after the end of each quarter we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Available cash generally means, for each fiscal quarter all cash on hand at the end of the quarter:
•
less the amount of cash reserves established by our general partner to:
•
provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);
•
comply with applicable law, any of our debt instruments or other agreements; or
•
provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;
•
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our working capital facility with Williams and in all cases are used solely for working capital purposes or to pay distributions to partners.
If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:
•
any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•
our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.
We will make distributions of available cash from operating surplus for any quarter in the following manner:
•
first, 98% to all unitholders, pro rata, and 2% to our general partner, until each outstanding common unit has received the minimum quarterly distribution for that quarter; and
•
thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the incentive percentages below.
Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Item 6.
Item 6.
Selected Financial and Operational Data
The following table shows selected financial and operating data of Williams Partners L.P., Wamsutter LLC and Discovery Producer Services LLC for the periods and as of the dates indicated. We derived the financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this document. All other financial data are derived from our financial records.
Because Four Corners, Wamsutter and the additional 20% interest in Discovery were owned by affiliates of Williams at the time of these acquisitions, these transactions were between entities under common control, and have been accounted for at historical cost. Accordingly, our selected financial and operational data have been recast to reflect the combined historical results of these common control acquisitions throughout the periods presented. These acquisitions have no impact on historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information concerning significant trends in the financial condition and results of operations.
(a)
The $16.9 million impairment of our equity investment in Discovery in 2004 reduced the investment balance.
(b)
Our operations are treated as a partnership with each member being separately taxed on its ratable share of our taxable income. Therefore, we have excluded income tax expense from this financial information.
(c)
The period of August 23, 2005 through December 31, 2005.
(d)
In December 2003, we made a $101.6 million capital contribution to Discovery, which Discovery subsequently used to repay maturing debt. We funded this contribution with an advance from Williams. Prior to the closing of our initial public offering, Williams forgave the entire advances from affiliates balance.
(e)
Because Four Corners, Wamsutter and the additional 20% in Discovery were owned by affiliates of Williams at the time of their acquisition by us, the acquisitions are accounted for as a combination of entities under common control, whereby the assets and liabilities are combined with Williams Partners L.P. at their historical amounts for all periods presented. This accounting causes a reduction of the capital balance for the general partner for the difference between the historical cost of these assets and liabilities and the aggregate consideration paid to the general partner.
Item 7.
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Please read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and related notes included in Item 8
of this annual report.
Overview
We are principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing NGLs. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:
•
Gathering and Processing - West. Our West segment includes Williams Four Corners LLC (Four Corners) and certain ownership interests in Wamsutter LLC (Wamsutter) consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 50% of the initial Class C units (or 20 Class C units) representing limited liability company membership interests in Wamsutter (together, the Wamsutter Ownership Interests). The Four Corners system gathers and processes or treats approximately 37% of the natural gas produced in the San Juan Basin and connects with the five pipeline systems that transport natural gas to end markets from the basin. The Wamsutter system gathers approximately 69% of the natural gas produced in the Washakie Basin and connects with three pipeline systems that transport natural gas to end markets from the basin.
•
Gathering and Processing - Gulf. Our Gulf segment includes (1) our 60% ownership interest in Discovery Producer Services LLC (Discovery) and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and a natural gas liquids (NGL) fractionator in Louisiana. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such.
•
NGL Services. Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.
Executive Summary
In 2007, a significant achievement was the December acquisition of the Wamsutter Ownership Interests from The Williams Companies, Inc. (Williams) for $750.0 million. The Wamsutter system serves the Washakie basin, which has stable production and high growth potential. At Four Corners, record commodity margins largely offset the negative impacts of the fire at the Ignacio plant, increased operating expenses and lower gathered volumes. Important capital investments were completed at Four Corners, which we believe will lead to slightly increased gathering volumes in 2008. We also acquired an additional 20% interest in Discovery from Williams in June for $78.0 million. Discovery has recently produced record quarterly profits and looks forward to continued strong performance in 2008. At Conway, we continue to see strong demand for leased storage and new product upgrade services. We have increased unitholder distributions each quarter since our initial public offering (IPO) and our fourth-quarter 2007 distribution was 22% higher than the fourth-quarter 2006 distribution. Our relationship with Williams and ability to raise capital has us well-positioned for continued growth through both internal projects and acquisition transactions with Williams and other third parties.
Recent Events
Conversion of Subordinated Units. On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our
outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.
Acquisition of Wamsutter Ownership Interests. On December 11, 2007, we acquired the Wamsutter Ownership Interests from Williams for aggregate consideration of $750.0 million. The acquisition was financed with the debt and equity issuances described below.
•
Issuance of Common Units. We sold 9,250,000 common units in a public offering. We received net proceeds of approximately $335.2 million from the sale of the common units after deducting underwriting discounts but before estimated offering expenses. On January 9, 2008, we sold an additional 800,000 common units to the underwriters upon the underwriters’ partial exercise of their option to purchase additional common units.
•
Issuance of Common Units to Williams. We issued approximately $157.2 million of common units, or 4,163,527 common units, to Williams. On January 9, 2008, we used the net proceeds from the partial exercise of the underwriters’ option to redeem 800,000 common units from Williams at a price per common unit of $36.24 ($37.75, net of underwriter discount).
•
Increase in General Partner’s Capital Account. The general partner contributed approximately $10.3 million to maintain its 2% general partner interest.
•
Term Loan. We borrowed $250.0 million under the term loan provisions of our new credit facility discussed below.
Williams Partners L.P.’s New Credit Facility. We entered into a $450.0 million five-year senior unsecured credit facility comprised initially of a $250.0 million term loan used to finance a portion of the aggregate consideration for the Wamsutter Ownership Interests and a $200.0 million revolving credit facility, which is available for borrowings and letters of credit. On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility and; therefore, no longer have access to a $75.0 million borrowing capacity under that facility.
Ignacio gas processing plant fire. On November 28, 2007, there was a fire at the Ignacio gas processing plant. This fire resulted in severe damage to the facility’s cooling tower, control room, adjacent warehouse buildings and control systems. The plant was shut down from November 28 to January 18, 2008. There were no injuries as a result of this incident and the plant now has full cryogenic recovery and fractionation facilities in operation.
Additional Investment in Discovery. On June 28, 2007, we acquired an additional 20% limited liability company interest in Discovery from Williams for aggregate consideration of $78.0 million.
Conversion of Class B Units. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis by a majority vote of common units eligible to vote.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measures to analyze our segment performance, including the performance of Wamsutter and Discovery. These measurements include:
•
Four Corners’ and Wamsutter’s gathering and processing volumes;
•
Four Corners’ and Wamsutter’s net liquids margin;
•
Discovery’s and Carbonate Trend’s pipeline throughput volumes;
•
Discovery’s gross processing margins;
•
Conway’s fractionation volumes;
•
Conway’s storage revenues;
•
operating and maintenance expenses; and
•
general and administrative expenses.
Four Corners
Gathering and Processing Volumes. The gathering volumes on our Four Corners system and volumes processed at the Ignacio, Kutz and Lybrook natural gas processing plants are important components of maximizing its profitability. We gather approximately 37% of the San Juan Basin’s natural gas production on our Four Corners system at approximately 6,400 receipt points under mostly fee-based contracts. Our gathering volumes from existing wells connected to our pipeline will naturally decline over time. Accordingly, to maintain or increase gathering volumes we must continually obtain new supplies of natural gas. Our Four Corners system processes natural gas under keep-whole, percent-of-liquids, fee-based and fee-based and keep-whole contracts. Our processing volumes are largely dependent on the volume of natural gas gathered on our Four Corners’ system.
Net Liquids Margin. The net liquids margin is an important measure of Four Corners’ ability to maximize the profitability of its processing operations. Liquids margin is derived by deducting the cost of shrink replacement gas from the revenue Four Corners receives from the sale of its NGLs, which is net of transportation and fractionation charges. Shrink replacement gas refers to natural gas that is required to replace the Btu content lost when NGLs are extracted from the natural gas stream. Under certain agreement types, Four Corners receives NGLs as compensation for processing services provided to its customers. The net liquids margin will either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas and changes in the cost of transporting and fractionating the NGLs.
Wamsutter
Gathering and Processing Volumes. The gathering volumes on the Wamsutter system and volumes processed at the Echo Springs natural gas processing plant are important components of maximizing its profitability. The Wamsutter pipeline system gathers approximately 69% of the natural gas produced in the Washakie Basin and connects with the Colorado Interstate Gas, Wyoming Interstate Gas, Southern Star Central Gas Pipeline, and Rockies Express systems that transport natural gas to end markets from the basin. Wamsutter’s gathering volumes from existing wells connected to our pipelines will naturally decline over time. Accordingly, to maintain or increase gathering volumes Wamsutter must continually obtain new supplies of natural gas. The Wamsutter system processes natural gas under keep-whole and fee-based contracts. Wamsutter’s processing volumes are largely dependent on the volume of natural gas gathered on its system.
Net Liquids Margin. The net liquids margin is an important measure of Wamsutter’s ability to maximize the profitability of its processing operations. Liquids margin is derived by deducting the cost of shrink replacement gas from the revenue Wamsutter receives from the sale of its NGLs, which is net of transportation and fractionation charges. Shrink replacement gas refers to natural gas that is required to replace the Btu content lost when NGLs are extracted from the natural gas stream. Under certain agreement types, Wamsutter receives NGLs as compensation for processing services provided to its customers. The net liquids margin will either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas and changes in the cost of transporting and fractionating the NGLs.
Discovery and Carbonate Trend
Pipeline Throughput Volumes. We view throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline as an important component of measuring the results of these assets. We gather and transport natural gas under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our and Discovery’s pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator, we and Discovery must continually obtain new supplies of natural gas. Our and Discovery’s ability to maintain existing supplies of natural gas and obtain new supplies are impacted by (1) the level of workovers or
recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines and (2) our ability to compete for volumes from successful new wells in other areas. We and Discovery routinely monitor producer activity in the areas served by Discovery and Carbonate Trend and pursue opportunities to connect new wells to these pipelines.
Gross Processing Margins. We view total gross processing margins as an important measure of Discovery’s ability to maximize the profitability of its processing operations. Gross processing margins include revenue derived from:
•
the rates stipulated under fee-based contracts multiplied by the actual volumes processed;
•
sales of NGL volumes received under certain processing contracts for Discovery’s account and keep-whole contracts; and
•
sales of natural gas volumes that are in excess of operational needs.
The associated costs, primarily shrink replacement gas and fuel gas, are deducted from these revenues to determine gross processing margin. Discovery’s mix of processing contract types and its operation and contract optimization activities are determinants in processing revenues and gross margins.
Conway
Fractionation Volumes. We view the volumes that we fractionate at the Conway fractionator as an important measure of our ability to maximize the profitability of this facility. We provide fractionation services at Conway under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes fractionated.
Storage Revenues. Our storage revenues are derived by applying the average demand charge per barrel to the total volume of storage capacity under contract. Given the nature of our operations, our storage facilities have a relatively higher degree of fixed versus variable costs. Consequently, we view total storage revenues, rather than contracted capacity or average pricing per barrel, as the appropriate measure of our ability to maximize the profitability of our storage assets and contracts. Total storage revenues include the monthly recognition of fees received for the storage contract year and shorter-term storage transactions.
Operating and Maintenance Expenses
Operating and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, leased compression services, contract services, fuel, utilities, materials, supplies, insurance and ad valorem taxes comprise the most significant portion of operating and maintenance expenses. We have experienced increased operating and maintenance expenses in recent years due to the growth of the oil and gas industry, which has increased competition for resources. Other than system gains and losses, rented compression services and fuel expense, these expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate depending on the activities performed during a specific period. For example, plant overhauls and turnarounds result in increased expenses in the periods during which they are performed. In the course of providing gathering, processing and treating services to our customers, we realize over and under deliveries of customers’ products and over and under purchases of shrink replacement gas when our purchases vary from operational requirements. In addition, we realize gains and losses which we believe are related to inaccuracies inherent in the gas measurement process. These gains and losses are reflected in operating and maintenance expense as system gains and losses. These system gains and losses are an unpredictable component of our operating costs. Leased compression services are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. We include fuel cost in our operating and maintenance expense although it is generally recoverable from our customers in our NGL Services segment. As noted above, fuel costs in our Gathering and Processing - Gulf segment are a component in assessing our gross processing margins.
General and Administrative Expenses
We are charged for certain administrative expenses by Williams and its Midstream segment of which we are a part. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams and Midstream at our request. Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are allocated to us. These allocated corporate administrative expenses are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of direct and allocated administrative expenses is reflected in General and administrative expense - Affiliate in the accompanying Consolidated Statements of Income.
Under the omnibus agreement, Williams gives us a quarterly credit for general and administrative expenses. These amounts are reflected as a capital contribution from our general partner. The annual amounts of the credits are as follows: $3.9 million in 2005 ($1.4 million pro-rated for the portion of the year from August 23 to December 31), $3.2 million in 2006, $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009. We record total general and administrative costs, including those costs that are subject to the credit by Williams, as an expense, and we record the credit as a capital contribution by our general partner. Accordingly, our net income does not reflect the benefit of the credit received from Williams. However, the cost subject to this credit is allocated entirely to our general partner.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. The selection of these policies has been discussed with the audit committee of the board of directors of our general partner. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
Impairment of Long-Lived Assets and Investments
We evaluate our long-lived assets and investments for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of certain long-lived assets or that the decline in value of an investment is other-than-temporary.
During 2007, we determined that the carrying value of our Carbonate Trend pipeline may not be recoverable because of forecasted declining cash flows. As a result, we recognized an impairment charge of $10.4 million to reduce the carrying value to managements’ estimate of fair value at December 31, 2007. (See Note 7, Other (Income) Expense, in our Notes to Consolidated Financial Statements.) Our computations utilized judgments and assumptions in the following areas:
•
estimated future volumes and rates; and
•
estimated earnings multiples that could be realized in a sale of the assets.
Our projections are sensitive to changes in the above assumptions. A change to the estimated earnings multiple of one times would increase or decrease our fair value estimate by approximately $1.2 million.
Accounting for Asset Retirement Obligations
We record asset retirement obligations for legal and contractual obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset in the period in which it is incurred if a reasonable estimate of fair value can be made. At December 31, 2007, we have an accrued asset retirement obligation liability of $8.7 million including estimated retirement costs associated with the abandonment of Four Corners’ gas processing and compression facilities located on leased land, Four Corners’ wellhead connections on federal land, Conway’s underground storage caverns and brine ponds in accordance with KDHE regulations and the Carbonate Trend pipeline. Our estimate utilizes
judgments and assumptions regarding the extent of our obligations, the costs to abandon and the timing of abandonment. Our recorded asset retirement obligation is based on the assumption that the abandonment of our Four Corners and Conway assets generally occurs in approximately 50 years. If this assumption had been changed to 30 years in 2007, and the expected retirement date for the Carbonate Trend pipeline had been significantly shortened, the recorded asset retirement obligation would have increased by approximately $3 million to $4 million. (See Note 8, Property, Plant and Equipment, in our Notes to Consolidated Financial Statements.)
Environmental Remediation Liabilities
We record liabilities for estimated environmental remediation liabilities when we assess that a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2007, we have an accrual for estimated environmental remediation obligations of $4.0 million. This remediation accrual is revised, and our associated income is affected, during periods in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental remediation upon our assumptions and estimates regarding what remediation work and post-remediation monitoring will be required and the costs of those efforts, which we develop from information obtained from outside consultants and from discussions with the applicable governmental authorities. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarter or annual period. (Please read “- Environmental” and Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements.)
Revenue Recognition - Derivative Instruments and Hedging Activities
We hold a portfolio of nontrading energy contracts. We review these contracts to determine whether or not they are derivatives. If they are derivatives, we further assess whether the contracts qualify for either cash flow hedge accounting or the normal purchases and normal sales exception.
The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in achieving offsetting cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.
Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.
The fair value of derivative contracts is determined based on the nature of the transaction and the market in which transactions are executed. We also incorporate assumptions and judgments about counterparty performance and credit considerations in our determination of their fair value. Our contracts are generally executed in over-the-counter markets with quoted prices. The fair value of all derivative contracts is
continually subject to change as the underlying commodity market changes and our assumptions and judgments change.
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
(1)
+ = Favorable Change; ( ) = Unfavorable Change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
2007 vs.
Revenues increased $9.4 million, or 2%, due primarily to higher revenues in our Gathering and Processing - West segment, slightly offset by lower revenues in our NGL Services segment. Revenues in our Gathering and Processing - West segment increased due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. Revenues in our NGL Services segment decreased due primarily to lower product sales and fractionation revenues, partially offset by higher storage and product upgrade fee revenues. These fluctuations are discussed in detail in the “- Results of Operations - Gathering and Processing - West” section and “- Results of Operations - NGL Services” sections.
Product cost and shrink replacement increased $6.2 million, or 4%, due primarily to increased NGL purchases from producers in our Gathering and Processing - West segment, partially offset by lower shrink requirements related primarily to the fire at Ignacio in the same segment and decreased product sales volumes in our NGL Services segment. These fluctuations are discussed in detail in the “- Results of Operations - Gathering and Processing - West” and “- Results of Operations - NGL Services” sections.
Operating and maintenance expense increased $7.1 million, or 5%, due primarily to higher expense in our Gathering and Processing - West segment, partially offset by lower expense in our NGL Services segment. Operating and maintenance expense in our Gathering and Processing - West segment increased due primarily to higher fuel costs, rent expense and leased compression, partially offset by lower maintenance costs. Operating and maintenance expense in our NGL Services segment decreased due primarily to lower fuel and power costs related to the lower fractionator throughput. These fluctuations are discussed in detail in the “- Results of Operations - Gathering and Processing - West” and “- Results of Operations - NGL Services” sections.
General and administrative expense increased $6.2 million, or 16%, due primarily to higher Williams’ technical support services and other charges allocated by Williams to us for various administrative support functions.
Other (income) expense changed from $2.5 million income in 2006 to $12.1 million expense in 2007, due primarily to the fourth quarter 2007 impairment of the Carbonate Trend pipeline and a $3.6 million gain in 2006 on the sale of the La Maquina carbon dioxide treating facility in the Gathering and Processing - West segment.
Operating income declined $28.1 million, or 20%, due primarily to lower segment operating income in our Gathering and Processing - West segment, the fourth-quarter 2007 impairment of the Carbonate trend pipeline and higher general and administrative expense, partially offset by higher storage revenues and product storage upgrade fees and lower operating and maintenance expenses in our NGL Services segment. Segment operating income decreased in our Gathering and Processing - West segment due primarily to the impact of the Ignacio plant fire. These fluctuations are discussed in detail in the “- Results of Operations - Gathering and Processing - West” and “- Results of Operations - NGL Services” sections.
Equity earnings from Wamsutter increased $14.5 million, or 24%, due primarily to higher net liquids margins and fee-based gathering and processing revenues, partially offset by higher general and administrative expenses. Wamsutter’s results are discussed in detail in the “- Results of Operations - Gathering and Processing - West” section.
Equity earnings from Discovery increased $10.8 million, or 60%, due primarily to higher gross processing margins that more than offset lower fee-based revenues and higher operating and maintenance expense. Discovery’s results are discussed in detail in the “- Results of Operations - Gathering and Processing - Gulf” section.
Interest expense increased $48.5 million due primarily to interest on our $750.0 million senior unsecured notes. We issued $150.0 million in June 2006 and $600.0 million in December 2006 to finance our acquisition of Four Corners.
Interest income increased $1.4 million, or 87%, due to higher cash balances during the first and second quarters of 2007.
2006 vs.
Revenues increased $48.4 million, or 9%, due primarily to higher revenues in our Gathering and Processing - West segment reflecting increased product sales and gathering and processing revenues combined with increased storage revenues and product sales in our NGL Services segment. These increases are discussed in detail in the “- Results of Operations - Gathering and Processing - West” and “- Results of Operations - NGL Services” sections.
Operating and maintenance expense increased $25.5 million, or 20%, due primarily to higher compression, maintenance and labor costs in our Gathering and Processing - West segment. These increases are discussed in the “- Results of Operations - Gathering and Processing - West” section.
Operating income increased $23.7 million, or 20%, due primarily to our Gathering and Processing - West segment where higher net liquids margins and fee-based revenues were partially offset by higher operating and maintenance expense.
Equity earnings from Wamsutter increased $21.1 million, or 52%, due primarily to higher net liquids margins. These increases are discussed in detail in the “- Results of Operations - Gathering and Processing - West” section.
Equity earnings from Discovery increased $6.2 million, or 52%, due primarily to Discovery’s higher gross processing margins partially offset by higher operating and maintenance expense. These increases are discussed in detail in the “- Results of Operations - Gathering and Processing - Gulf” section.
Interest expense increased $1.6 million, or 19%, due primarily to $8.3 million of interest on our $750.0 million senior unsecured notes issued in June and December of 2006 to finance a portion of our acquisition of Four Corners. This increase was partially offset by $7.4 million lower interest following the forgiveness of advances from Williams in conjunction with the closing of our IPO on August 23, 2005.
Interest income increased $1.4 million due to interest earned on our cash balances following our IPO on August 23, 2005.
Results of operations - Gathering and Processing - West
The Gathering and Processing - West segment includes our Four Corners’ natural gas gathering, processing and treating assets and our ownership interest in Wamsutter.
Four Corners
2007 vs.
Revenues increased $11.5 million, or 2%, due primarily to $23.7 million higher product sales, partially offset by $9.5 million lower gathering and processing revenues and $2.7 million lower other revenues. Product sales increased due primarily to:
•
$24.2 million related to a 17% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods; and
•
$15.3 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $15.3 million discussed below.
These product sales increases were partially offset by $12.7 million lower revenues related to an 8% decrease in NGL volumes that Four Corners received under certain processing contracts. Based on 2006 prices, the $12.7 million includes approximately $9.3 million related to NGL volume reductions caused by the fire at the Ignacio gas processing plant in late November 2007.
Additionally, product sales decreased in 2007 as a result of $3.0 million lower condensate and LNG sales.
Gathering and processing revenues decreased $9.5 million, or 4%, due primarily to $8.3 million lower revenue from a 3% decrease in gathered and processed volumes and a $1.3 million decrease from a lower average rate charged for these services. Based on 2006 prices, the $8.3 million includes approximately $5.5 million related to gathered and processed volume reductions caused by the fire at the Ignacio plant. The decrease in the average rate was due primarily to a lower rate on one of our agreements with an affiliate that is adjusted annually based on changes in the average price of natural gas. The price of natural gas was substantially higher in 2006 than 2007.
Product cost and shrink replacement increased $10.4 million, or 7%, due primarily to:
•
$15.3 million increase from third party producers who elected to have us purchase their NGLs, which was offset by the corresponding increase in product sales revenues discussed above; and
•
$2.8 million increase from 5% higher average natural gas prices.
These increases were partially offset by $6.4 million from 10% lower volumetric shrink requirements under our Four Corners’ keep-whole processing contracts. Based on 2006 prices, the $6.4 million includes approximately $5.1 million related to reduced processing activity caused by the fire at the Ignacio plant.
Operating and maintenance expense increased $11.0 million, or 9%, due primarily to:
•
$9.6 million higher non-shrink natural gas purchases caused primarily by $7.9 million higher natural gas costs for steam generation at our Milagro facility. In 2006, our purchase of this natural gas from an affiliate of Williams was favorably impacted by that affiliate’s fixed price natural gas fuel contracts. These contracts expired in the fourth quarter of 2006. Additionally, in 2007 gathering fuel increased $3.3 million including approximately $2.3 million related to lower customer fuel reimbursements and operational inefficiencies caused by the fire at the Ignacio plant.
•
$3.9 million higher rent expense related to the purchase of a temporary special business license upon the expiration of a right-of-way agreement with the Jicarilla Apache Nation.
•
$3.4 million higher leased compression costs under agreements that are currently being renegotiated but are presently on month-to-month terms.
•
$1.0 million higher operating expense for our payment of the property insurance deductible for the fire at the Ignacio gas processing plant in late November 2007.
Partially offsetting these increases were $5.6 million lower materials and supplies related primarily to decreased equipment maintenance activity.
General and administrative expense - direct decreased $4.1 million, or 35%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.
Other (income) expense, net in 2006 includes a $3.6 million gain recognized on the sale of the LaMaquina treating facility. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.
Segment operating income decreased $12.1 million, or 8%, due primarily to the estimated $13.0 million combined impact of the fire at the Ignacio gas processing plant. Higher product sales margins, excluding the impact of the fire, of $17.5 million and $4.1 million lower direct general and administrative expense were offset by $7.7 million higher operating and maintenance expense excluding fire-related items, $4.0 million lower fee-based gathering and processing revenues not related to the fire, $4.2 million lower other (income) expense and $2.7 million lower miscellaneous revenue.
2006 vs.
Revenues increased $39.1 million, or 8%, due primarily to $24.6 million higher product sales and $14.3 million higher gathering and processing revenues. Product sales increased due primarily to:
•
$14.9 million related to a 12% increase in NGL volumes that we received under certain processing contracts. This increase was related primarily to equipment outages in 2005 and reduced ethane processing in the fourth quarter of 2005 caused by sharply higher natural gas prices following the hurricanes of 2005;
•
$13.5 million related to a 10% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods;
•
$4.1 million of higher condensate sales, which includes $1.9 million resulting from the recognition of two additional months of condensate revenue in 2006. Prior to 2006, condensate revenue had been recognized two months in arrears. As a result of more timely sales information now made available from third parties, we have recorded these on a current basis and thus have fully recognized this activity through December 31, 2006; and
•
$1.1 million of higher LNG sales related to an increase in volumes sold.
These product sales increases were partially offset by $9.0 million lower sales of NGLs on behalf of third party producers for whom we purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase the NGLs from the third party producers and sell them to an affiliate. This decrease is offset by lower associated product costs of $9.0 million discussed below.
The $14.3 million increase in fee-based gathering and processing revenues is due primarily to $15.2 million higher revenue from a 7% increase in the average gathering and processing rates, partially offset by $0.9 million lower revenue from a slight decrease in gathering and processing volumes. The average gathering and processing rates increased in 2006 largely as a result of inflation-sensitive contractual escalation clauses. One significant gathering agreement is adjusted based on changes in the average price of natural gas.
Product cost and shrink replacement gas costs decreased $5.7 million, or 3%, due primarily to:
•
$9.0 million lower purchases from third party producers who elected to have us purchase their NGLs which was offset by the corresponding decrease in product sales discussed above; and
•
$6.0 million from 8% lower average natural gas prices.
These decreases were partially offset by a $9.8 million increase from 16% higher volumetric shrink requirements under our keep-whole processing contracts.
Operating and maintenance expense increased $20.1 million, or 19%, due primarily to:
•
$13.4 million higher materials and supplies, outside services and other operating expenses related primarily to increased compression and maintenance costs;
•
$4.7 million higher labor and benefits caused by higher Williams’ annual incentive program costs and the addition of new personnel; and
•
$2.0 million higher non-shrink natural gas purchases due primarily to higher volumetric gathering fuel requirements and higher system losses.
Other (income) expense, net improved $3.1 million due primarily to a $3.6 million gain recognized on the sale of the LaMaquina treating facility in 2006. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.
Segment operating income increased $26.5 million, or 20%, due primarily to $24.7 million of higher net liquids margins resulting primarily from increased per-unit margins on higher NGL sales volumes, $14.3 million of higher fee-based gathering and processing revenues, $5.2 million from higher condensate and LNG sales, and the $3.1 million improvement in other (income) expense, net. These increases were partially offset by $20.1 million higher operating and maintenance expense.
Outlook for 2008
•
We anticipate that growth capital investments we completed in 2007 to support ConocoPhillips’ and other producer customers’ drilling activity, expansion opportunities and production enhancement activities should be sufficient to more than offset the historical decline and slightly increase 2008 average gathering and processing volumes above 2007.
•
We have realized above average net liquids margins at our gas processing plants in recent years due primarily to increasing prices for NGLs. Based on first-quarter 2008 prices for NGLs and natural gas and the derivatives described below, per-unit margins in 2008 could meet or exceed record levels realized in 2007. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are impossible to control and in particular NGL pricing is typically impacted negatively by recessionary economic conditions.
•
In December 2007 and January 2008, we entered into financial swap contracts to hedge 5.4 million gallons of monthly forecasted NGL sales for February through December 2008. Of the 5.4 million gallons, 4.2 million are ethane sales. We also entered into fixed price natural gas purchase contracts to hedge the price of our natural gas shrink replacement associated with these NGL sales, which are derived from keep-whole processing contracts. As a result, we have effectively hedged a margin of $31.2 million or an average $0.52 per gallon on these NGL sales in 2008.
•
We anticipate that operating costs, excluding compression and system gains and losses, will remain stable as compared to 2007. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. System gains and losses are an unpredictable component of our operating costs.
•
Our right of way agreement with the Jicarilla Apache Nation (JAN), which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires February 29, 2008. We are engaged in discussions with the JAN designed to result in the sale of our gathering assets which are located on or are isolated by the JAN lands. Provided the parties are able to reach an acceptable value on the sale of the subject gathering assets, our expectation is that we will nonetheless maintain partial revenues associated with gathering and processing downstream of the JAN lands and continue to operate the gathering assets on the JAN lands for an undetermined period of time beyond February 29, 2008. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 million to $30 million of Four Corners’ annual gathering and processing revenue less related product costs.
Wamsutter
Wamsutter is accounted for using the equity method of accounting. As such, our interest in Wamsutter’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Wamsutter.
2007 vs.
Revenues decreased $1.2 million, or 1%, due primarily to a $12.3 million decrease in product sales revenues, substantially offset by a $10.0 million increase in gathering and fee-based processing revenues.
Product sales revenues decreased $12.3 million, or 11%, due primarily to:
•
$20.8 million related to a 20% decrease in NGL volumes that Wamsutter received under certain processing contracts. Effective January 1, 2007, one significant customer made an election to switch from a keep-whole processing arrangement to a fee-based processing arrangement for three years. This significantly decreased the NGL volumes received by Wamsutter under its keep-whole processing contracts; and
•
$3.4 million lower sales of NGLs on behalf of third party producers who sell their NGLs to Wamsutter under their contracts. Under these arrangements, Wamsutter purchases the NGLs from the third party producers and sells them to an affiliate. This decrease is offset by lower associated product costs of $3.4 million discussed below.
These product sales decreases were partially offset by a $12.1 million increase related to 14% higher average NGL sales prices resulting from an increase in market prices for these commodities between the two periods.
Gathering and fee-based processing revenues increased $5.6 million due to a 9% increase in the average fee received for these services and $4.4 million due to an 8% increase in volumes. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues from completed gathering system expansion projects. Certain agreements provide incremental fee-based revenues upon the completion of projects that lower system pressures, allowing these customers to flow higher volumes from their existing wells.
Other revenues increased $1.0 million, or 19%, due primarily to higher revenue from minimum throughput provisions under certain gathering contracts.
Product cost and shrink replacement decreased $25.0 million, or 35%, due primarily to:
•
$11.2 million decrease from 21% lower average natural gas prices. Our 2007 net liquids margins were impacted favorably by very low local shrink replacement natural gas costs in the Rocky Mountain area as compared with other natural gas markets;
•
$10.4 million decrease from 16% lower volumetric shrink requirements under Wamsutter’s keep-whole processing contracts following the election of one customer to switch to fee-based processing discussed above; and
•
$3.4 million lower product cost related to lower sales of NGLs on behalf of third party producers who sell their NGLs to Wamsutter under their contracts as discussed above.
Operating and maintenance expense increased $1.2 million, or 7%, due primarily to:
•
$4.2 million higher materials and supplies and outside services expense caused primarily by increased equipment maintenance activity; and
•
$1.6 million from various smaller increases for rent, labor and utilities.
These increases were partially offset by $4.9 million lower non-shrink natural gas purchases due primarily to higher system gains.
Depreciation and accretion expense increased $2.2 million, or 14%, due primarily to new assets placed into service.
General and administrative expenses increased $3.8 million, or 42%, due primarily to higher charges allocated by Williams to Wamsutter for various technical and administrative support functions.
Net income increased $15.7 million, or 25%, due primarily to $12.9 million higher net liquids margins and $10.0 million higher gathering and fee-based processing revenues, partially offset $3.8 million higher general and administrative expenses and $2.2 million higher depreciation and accretion expense.
2006 vs.
Revenues decreased $0.5 million due primarily to an $8.4 million decrease in product sales revenues substantially offset by a $7.4 million increase in gathering and fee-based processing revenues.
Product sales revenues decreased $8.4 million, or 7%, due primarily to:
•
$13.1 million related to a 12% decrease in NGL volumes that Wamsutter received under certain processing contracts. The total gas available for processing increased from 2005 to 2006; however, due to limited plant capacity, not all of this increased volume could be processed. The increase in total gas available for processing generally resulted in greater NGL volumes for Wamsutter’s customers and lower NGL volumes received under its keep-whole processing contracts; and
•
a $4.7 million decrease in sales of excess shrink replacement gas. Wamsutter sold substantial volumes of excess shrink replacement gas during the fourth quarter of 2005. Following the hurricanes of 2005, there were unusually high natural gas prices and reduced ethane processing which caused Wamsutter to have excess shrink replacement natural gas. Wamsutter elected to take advantage of the higher natural gas prices and sell the excess natural gas rather than hold it for future requirements. There is a corresponding decrease in product costs discussed below.
These product sales decreases were partially offset by a $9.0 million increase related to 9% higher average NGL sales prices resulting from an increase in market prices for these commodities between the two periods.
Gathering and fee-based processing revenues increased $4.2 million due to an 8% increase in the average fee received for these services and $3.3 million due to a 7% increase in volumes. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues discussed previously.
Product cost and shrink replacement decreased $29.3 million, or 29%, due primarily to:
•
$13.1 million decrease from 17% lower average natural gas prices;
•
$11.7 million decrease from 13% lower volumetric shrink requirements under keep-whole processing contracts due to limited plant processing capacity discussed above; and
•
$4.7 million lower product cost related to the sale of excess shrink replacement gas as discussed above.
Operating and maintenance expense increased $4.5 million, or 36%, due primarily to a $2.1 million increase in non-shrink natural gas purchases resulting from higher system losses, a $1.0 million increase in rental expense for leased compression added in late 2005 and a $0.5 million increase in labor and benefits expense.
Depreciation and accretion expense increased $1.9 million, or 13%, due primarily to new assets placed into service in 2006.
Net income increased $21.2 million, or 52%, due primarily to $20.9 million in higher net liquids margins and $7.4 million higher gathering and fee-based processing revenues, partially offset by $4.5 million higher operating and maintenance expense and $1.9 million higher depreciation and accretion expense.
Outlook for 2008
•
Compared to 2007, we anticipate that sustained drilling activity, expansion opportunities and production enhancement activities by producers should be sufficient to more than offset the historical production decline and to increase average gathering volumes.
•
Total gas available for processing has increased in recent years; however, due to limited plant capacity, not all of this increased volume could be processed. This results in lower NGL volumes received under keep-whole processing contracts. In 2008, we anticipate that a new agreement providing us with third party processing at Colorado Interstate’s Rawlins natural gas processing plant will increase the processing capacity available to Wamsutter by 80 MMcf/d or approximately 20%. We anticipate that this third party processing will result in an increase in NGL volumes sold by Wamsutter.
•
In 2007, Wamsutter realized record high net liquids margins at its Echo Springs plant. The 2007 net liquids margins were significantly impacted by very low local shrink replacement natural gas costs as compared with other natural gas markets. We do not expect our shrink replacement natural gas costs will remain at these levels during 2008. Accordingly, we expect per-unit margins in 2008 will remain higher in relation to five-year historical averages, but below the record levels realized in 2007.
•
Operating costs, excluding system gains and losses and new third-party processing fees at the Colorado Interstate’s Rawlins plant, are expected to be approximately consistent with those in 2007. System gains and losses are an unpredictable component of Wamsutter’s operating costs. Additionally, the new third-party processing at Colorado Interstate’s Rawlins plant mentioned above requires that we pay a fee per MMbtu processed that will add approximately $4.0 million to $5.0 million in operating costs.
Results of operations - Gathering and Processing - Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership interest in Discovery.
Carbonate Trend
2007 vs.
Segment operating loss increased $11.2 million due primarily to the $10.4 million fourth quarter 2007 impairment of the Carbonate Trend pipeline. (See Note 7, Other (Income) Expense, of our Notes to Consolidated Financial Statements.)
2006 vs.
Segment operating income decreased $1.8 million from income of $1.6 million in 2005 to a loss of $0.2 million in 2006 due to the $0.9 million increase in operating and maintenance expense associated mainly with increased insurance premiums following 2005 hurricane activity. Additionally, 2005 included $0.5 million in revenues from the settlement of a contractual volume deficiency payment.
Discovery
Discovery is accounted for using the equity method of accounting. As such, our interest in Discovery’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Discovery.
2007 vs.
Revenues increased $63.4 million, or 32%, due primarily to $73.8 million higher product sales, partially offset by a $9.9 million reduction in fee-based transportation, gathering, processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas Pipeline (TGP) and the Texas Eastern Transmission Company (TETCO) open season agreements. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita in 2005. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006 and in October 2006 we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.
Product sales increased $73.8 million primarily due to:
•
$36.8 million from higher NGL volumes sold under certain processing contracts, including the October 2006 TETCO agreement, which is a percent-of-liquids agreement;
•
$26.2 million from higher average NGL prices received for these NGLs;
•
$8.1 million increase in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts; and
•
$2.7 million from higher sales of excess fuel and shrink replacement gas.
The $9.9 million decrease in fee-based transportation, gathering, processing and fractionation revenues is due primarily to the reduced fee-based revenues related to processing TGP and TETCO volumes under the open season agreements discussed above.
Product cost and shrink replacement increased $36.2 million, or 30%, due primarily to
•
$19.4 million higher volumetric natural gas requirements from increased processing activity;
•
$7.8 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs; and
•
$2.9 million higher product cost associated with the excess fuel and shrink replacement gas sales discussed above.
Operating and maintenance expense increased $5.9 million, or 26%, due primarily to $2.7 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years, $1.6 million from costs related to decommissioning two pipelines and other increased repair, maintenance and labor expenses.
Other (income) expense, net changed from $0.7 million of income in 2006 to $1.5 million of expense in 2007. The increased expense was due primarily to a decrease in foreign currency transaction gains and the loss on retirement of the two pipelines that were decommissioned. The non-cash foreign currency transaction gains resulted from the revaluation of restricted cash accounts denominated in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, for the construction of the Tahiti pipeline lateral expansion project.
Net income increased $18.0 million, or 60%, due primarily to $39.0 million higher gross processing margins resulting from higher NGL sales volumes and NGL prices, partially offset by $9.9 million lower fee-based transportation, gathering, processing and fractionation revenues, $5.9 million higher operating and maintenance expense and $2.2 million higher other expense.
2006 vs.
Revenues increased $74.6 million, or 61%, due primarily to higher NGL product sales from the purchasing of customers’ NGLs. In addition, the TGP and TETCO open season agreements, which began in the last quarter of 2005, contributed an increase of $7.5 million. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. TGP’s
open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006, and in October we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.
•
Product sales increased $59.9 million for NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts. These sales were offset by higher associated product costs of $59.9 million discussed below.
•
Product sales also increased $18.1 million due to a 54% increase in NGL volumes that Discovery received under certain processing contracts and $5.3 million due to 10% higher average NGL sales prices related to these volumes. NGL sales volumes in 2006 were higher due partly to the lack of hurricane-related disruptions in 2006. In addition, exceptionally strong commodity margins compelled our customers to process their natural gas rather than by-pass, which led to higher product sales revenues on our percent-of-liquids and keep-whole processing contracts.
•
Transportation revenues increased $3.1 million, including $2.4 million in additional fee-based revenues related to the TGP and TETCO open season agreements discussed above.
•
Fee-based processing and fractionation revenues increased $2.7 million due primarily to $5.1 million in additional fee-based revenues related to processing the TGP and TETCO open seasons volumes discussed above, partially offset by lower by-pass revenues.
Partially offsetting these increases were the following:
•
Product sales decreased $10.0 million due to the absence of excess fuel and shrink replacement gas sales made in 2005.
•
Gathering revenues decreased $3.8 million due primarily to lower gathered volumes and rates and a $1.4 million deficiency payment received in the first quarter of 2005.
Product cost and shrink replacement increased $55.1 million, or 85%, due primarily to $59.9 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $6.7 million higher costs related primarily to increased processing volumes in 2006, partially offset by a $10.0 million decrease due to the absence of excess fuel and shrink replacement gas sales in 2006.
Operating and maintenance expense increased $12.9 million, or 127%, due primarily to a $10.7 million credit recognized in 2005 related to amounts previously deferred for net system gains from 2002 through 2004. These deferred gains were recognized following the acceptance in 2005 of a filing with the FERC. Additionally, Discovery had higher fuel costs caused by increased processing activity and $1.8 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years, partially offset by $1.0 million insurance deductible expensed in 2005.
Depreciation and accretion expense increased $0.7 million, or 3%, due primarily to the market expansion project placed in service in September 2005.
Interest income increased $0.7 million due primarily to interest earned on funds restricted for use in the construction of the Tahiti pipeline lateral expansion project.
Other (income) expense, net improved $2.8 million due primarily to a net improvement of $3.1 million in foreign currency transaction gains from the revaluation of restricted cash accounts denominated in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, for the construction of the Tahiti pipeline lateral expansion project. We are required to pay a significant portion of the construction costs in Euros.
Net income increased $9.3 million, or 44%, due primarily to $18.1 million higher gross processing margins and $7.5 million higher revenues from TGP and TETCO open seasons, partially offset by $12.9 million higher operating and maintenance and $3.8 million lower other gathering revenues.
Outlook for 2008
Discovery
•
Discovery’s Tahiti pipeline lateral was installed on the sea bed in February 2007. Chevron had scheduled initial throughput to begin in mid-2008, but in 2007 announced that it was facing delays because of metallurgical problems discovered in their facility’s mooring shackles. Chevron recently announced that it expects first production by the third quarter of 2009. Discovery’s revenues from the Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays Chevron experiences in bringing their production online impact the initial timing of revenues for Discovery.
•
Discovery’s Larose gas processing plant has been operating at near capacity. We expect that additional processing volumes from the TGP system in 2008 may replace some of the processing volumes previously coming from the TETCO system; and therefore, the Larose plant will continue to remain at near capacity throughout 2008. The additional volumes from TGP will require facilities modifications, which may be funded by a 2008 cash call to Discovery’s members.
•
The TETCO agreement was recently extended through May 2008 at which time we expect no further volumes under this agreement. Current flowing volumes are approximately 170 BBtu/d.
•
With the current oil and natural gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the limited availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits the ability of producers to bring identified reserves to market quickly. This will prolong the timeframe over which these reserves will be developed. We expect Discovery to be successful in competing for a portion of these new volumes.
•
In February 2008, Discovery executed agreements with LLOG Exploration Company to provide production handling, transportation, processing and fractionation services for their MC 705 and 707 production.
•
Gross processing margins have been at record high levels due to commodity prices for NGLs and natural gas and Discovery’s mix of processing contract types and its operation and optimization activities. We expect that 2008 gross processing margins will remain favorable to historical averages. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that are impossible to control and, in particular, NGL pricing is typically impacted negatively by recessionary economic conditions.
•
We expect Discovery’s 2008 results could be favorably impacted by approximately $3.0 million if its recently approved FERC rate filing pertaining to the regulated portion of its business becomes final and effective.
Results of operations - NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50% interest in the Conway fractionator.
2007 vs.
Segment revenues decreased $1.5 million, or 3%, due primarily to lower product sales and fractionation revenues, partially offset by higher storage and product upgrade fee revenues. The significant components of the revenue fluctuations are addressed more fully below.
•
Product sales decreased $4.7 million due to lower sales volumes. This decrease was offset by the related decrease in product cost discussed below.
•
Fractionation revenues decreased $2.1 million due primarily to 11% lower fractionation volumes and 7% lower rates. Fractionation throughput was lower during 2007 due to a customer’s decision to fractionate a percentage of their volumes outside of the Mid-Continent region for three months. This decision was based on current prices being paid for fractionated products outside of the Mid-Continent region. The lower fractionation rates relate to the pass through to customers of decreased fuel and power costs.
•
Storage revenues increased $2.8 million due primarily to higher average storage rates for all of 2007 and slightly higher levels of contracted storage.
•
Other revenue increased $2.5 million due primarily to low sulfur natural gasoline upgrade fees and higher volumes of trucking loading. The upgrade service began in late 2006.
Operating and maintenance expense decreased $4.1 million, or 14%, due primarily to lower fuel and power costs related to lower fractionator throughput and lower repairs and maintenance costs.
Product cost decreased $4.2 million, or 27%, due to the lower product sales volumes discussed above, resulting in a decrease in net margin of $0.5 million.
Depreciation and accretion expense increased $1.3 million, or 53%, due primarily to asset retirement obligation assumption changes and higher depreciation expense related to a larger property base.
General and administrative expense - direct increased $1.0 million, or 91%, due primarily to certain costs that were allocated to the partnership in 2006 but directly charged to the segment in 2007.
Segment profit increased $4.5 million, or 45%, due primarily to higher storage and product upgrade fee revenues, lower repair and maintenance costs and a favorable environmental reserve adjustment, partially offset by higher depreciation and accretion expense, higher general and administrative expense - direct and lower net margin on product sales.
2006 vs.
Segment revenues increased $10.2 million, or 21%, due primarily to higher storage, product sales and other revenues. The significant components of these revenue increases are addressed more fully below.
•
Storage revenues increased $4.9 million due primarily to higher average storage volumes from additional short-term storage leases caused by the reduced demand for propane during the mild 2006 winter and storage customers who held their NGLs in storage due to an inclining forward market.
•
Product sales were $2.6 million higher due primarily to the sale of surplus volumes created through our product optimization activities. This increase was more than offset by the related increase in product cost discussed below.
•
Other revenues increased $1.7 million due primarily to $1.3 million of fees charged for low sulfur natural gasoline upgrades that began in 2006.
Operating and maintenance expense increased $4.4 million, or 18%, due primarily to increased storage cavern workovers and increases to Conway’s environmental remediation liability, partially offset by favorable changes in product imbalance adjustments.
Product cost increased $3.7 million, or 31%, due to the higher product sales volumes discussed above as well as an increase in per-unit costs of 21%.
Segment profit increased $2.0 million, or 25%, due primarily to $10.2 million higher revenues, substantially offset by $8.1 million higher product cost and operating and maintenance expense.
Outlook for 2008
•
We expect 2008 storage revenues will remain approximately consistent with 2007 due to continued strong demand for propane and butane storage as well as higher priced specialty storage services.
•
We continue to perform a large number of storage cavern workovers and wellhead modifications to comply with KDHE regulatory requirements. We expect outside service costs to continue at current levels throughout 2008 to ensure that we meet the regulatory compliance requirements.
Financial Condition and Liquidity
We believe we have the financial resources and liquidity necessary to meet future requirements for working capital, capital and investment expenditures, debt service and quarterly cash distributions. We anticipate our sources of liquidity will include:
•
Cash and cash equivalents on hand;
•
Cash generated from operations, including cash distributions from Wamsutter and Discovery;
•
Insurance recoveries related to the fire at the Ignacio gas processing plant, which should generally be received as costs are incurred;
•
Capital contributions from Williams pursuant to an omnibus agreement; and
•
Credit facilities, as needed.
We anticipate our more significant liquidity requirements to be:
•
Maintenance and expansion capital expenditures for our Four Corners and Conway assets;
•
Four Corners repair expenditures related to the fire at the Ignacio gas processing plant, which should generally be reimbursed by insurance approximately as they are incurred;
•
Contributions we must make to Wamsutter LLC to fund certain of its expansion capital expenditures;
•
Interest on our long-term debt; and
•
Quarterly distributions to our unitholders.
These liquidity sources and cash requirements are discussed in greater detail below.
Wamsutter Distributions
The Wamsutter LLC Agreement provides for distributions of available cash to be made quarterly beginning in March 2008. Available cash is defined as cash generated from Wamsutter’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law and or debt instrument or other agreement to which it is a party.
Wamsutter will distribute its available cash as follows:
•
First, an amount equal to $17.5 million per quarter to the holder of the Class A membership interests. We currently own 100% of the Class A interests;
•
Second, an amount equal to the amount the distribution on the Class A membership interests in prior quarters of the current distribution year was less than $17.5 million per quarter to the holder of the Class A membership interests; and
•
Third, 5% of remaining available cash shall be distributed to the holder of the Class A membership interests and 95% shall be distributed to the holders of the Class C units, on a pro rata basis. We currently own 50% of the Class C units.
In addition, to the extent that at the end of the fourth quarter of a distribution year, the Class A member has received less than $70.0 million under the first and second bullets above, the Class C members will be required to repay any distributions they received in that distribution year such that the Class A member receives $70.0 million for that distribution year. If this repayment is insufficient to result in the Class A member receiving $70.0 million, the shortfall will not carry forward to the next distribution year. The initial distribution year for Wamsutter commenced on December 1, 2007 and ends on November 30, 2008. Subsequent distribution years for Wamsutter will commence on December 1 and end on November 30.
Additionally, each month during fiscal years 2008 through 2012 the Class B member, Williams, is obligated to pay to Wamsutter and Wamsutter is obligated to pay us a transition support payment in an amount equal to the amount by which Wamsutter’s general and administrative expenses exceed a certain cap. For 2008 the annualized cap is $5.0 million. Any such amounts received from the Class B member shall be distributed to us but shall not be counted for purposes of determining whether or not Wamsutter has distributed $70.0 million in aggregate annual distributions as described above.
Discovery Distributions
Discovery expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Discovery made the following 2006-2007 distributions to its members (all amounts in thousands):
*
Special distribution Discovery made after receipt of insurance proceeds.
**
On June 28, 2007, we closed on the acquisition of an additional 20% limited liability company interest in Discovery. Because this acquisition was effective July 1, 2007, we did not begin to receive 60% of Discovery’s distributions until October 2007.
Insurance Recoveries
As previously discussed, on November 28, 2007 the Ignacio gas processing plant sustained significant damages from a fire. The estimated total cost for fire-related repairs is approximately $27.0 million, including $26.0 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $11.0 million has been incurred as of December 31, 2007. We are funding these repairs with cash flows from operations and are seeking reimbursement from our insurance carrier. Additionally, we will seek reimbursement from our insurance carrier for approximately 13 days of lost profits under our business interruption policy.
Capital Contributions from Williams
Capital contributions from Williams required under the omnibus agreement consist of the following:
Indemnification of environmental and related expenditures, less any related insurance recoveries, for a period of three years ending August 2008 (for certain of those expenditures) up to a cap of $14.0 million. As of December 31, 2007 we have received $5.4 million from Williams for indemnified items since inception of the agreement in August 2005. Thus, approximately $8.6 million remains available for reimbursement of our costs on these items.
Additionally, under the omnibus agreement, we will receive an annual credit for general and administrative expenses of $1.6 million in 2008 and $0.8 million in 2009 and up to $3.4 million to fund our initial 40% share of the expected total cost of Discovery’s Tahiti pipeline lateral expansion project in excess of the $24.4 million we contributed during September 2005. As of December 31, 2007 we have received $1.6 million from Williams for the Tahiti-related indemnification.
Although we recently acquired an additional 20% ownership interest in Discovery, Tahiti-related indemnifications under the omnibus agreement continue to be based on the 40% ownership interest we held when this agreement became effective.
Credit Facilities
On December 11, 2007, in conjunction with the closing of our acquisition of the Wamsutter Ownership Interests, we entered into a $450.0 million senior unsecured credit agreement with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility available for borrowings and letters of credit and a $250.0 million term loan. Under certain conditions, the revolving credit facility may be increased up to an additional $100.0 million. Borrowings under this agreement must be repaid within 5 years. There were no amounts outstanding at December 31, 2007 under the revolving credit facility portion of this credit agreement.
On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility. As a result, we no longer have access to a $75.0 million borrowing capacity under that facility.
We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. We are required to reduce all borrowings under this facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. As of December 31, 2007 we had no outstanding borrowings under the working capital credit facility.
On December 11, 2007, Wamsutter entered into a $20.0 million revolving credit facility with Williams as the lender. This credit facility is available to fund working capital requirements and for other purposes. Borrowings under the credit facility mature on December 9, 2008 and bear interest at the one-month LIBOR. Wamsutter pays a commitment fee to Williams on the unused portion of the credit facility of 0.175% annually. As of December 31, 2007, Wamsutter had no outstanding borrowings under this credit facility.
Credit Ratings
The table below presents our current credit ratings on our senior unsecured long-term debt.
Capital Expenditures
The natural gas gathering, treating, processing and transportation, and NGL fractionation and storage businesses are capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital expenditures of these businesses consist primarily of:
•
Maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives; and
•
Expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.
Estimated capital expenditures for the year ending December 31, 2008 are as follows:
We expect to fund Four Corners’ and Conway’s maintenance and expansion capital expenditures with cash flows from operations. Four Corners’ maintenance capital expenditures include approximately $17.0 million related to well connections necessary to connect new sources of throughput for the Four Corners’ system which serve to offset the historical decline in throughput volumes. Four Corners expansion capital expenditures relate primarily to plant and gathering system expansion projects. Conway’s expansion capital expenditures relate to various small projects.
Wamsutter’s maintenance capital expenditures include approximately $18.0 million related to well connections necessary to connect new sources of throughput for the Wamsutter system which serve to offset the historical decline in throughput volumes. We expect Wamsutter will fund its maintenance capital expenditures through its cash flows from operations.
Wamsutter funds its expansion capital expenditures through capital contributions from its members as specified in its limited liability company agreement. This agreement specifies that expansion capital projects with expected total expenditures in excess of $2.5 million at the time of approval and well connections that increase gathered volumes beyond current levels be funded by contributions from its Class B membership, which we do not own. However, our ownership of the Class A membership interest requires us to provide capital contributions related to expansion projects with expected total expenditures less than $2.5 million at the time of approval.
Discovery will fund its maintenance and expansion capital expenditures either by cash calls to its members or from its cash flows from operations.
Debt Service - Long-Term Debt
We have $150.0 million senior unsecured notes outstanding that bear interest at 7.5% per annum payable semi-annually in arrears on June 15 and December 15 of each year. The senior notes mature on June 15, 2011.
We have $600.0 million of 7.25% senior unsecured notes outstanding. The maturity date of the notes is February 1, 2017. Interest is payable semi-annually in arrears on February 1 and August 1 of each year, beginning on August 1, 2007.
As discussed previously in “Credit Facilities,” we have a $250.0 million term loan outstanding. This borrowing must be repaid before December 11, 2012.
Cash Distributions to Unitholders
We have paid quarterly distributions to our unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recently declared quarterly distribution of $35.3 million was paid on February 14, 2008 to the general partner interest and common and subordinated unitholders of record at the close of business on February 7, 2008. This distribution included an incentive distribution to our general partner of approximately $4.2 million. On January 28, 2008, the board of directors of our general partner confirmed that, upon payment of the distribution to unitholders on February 14, 2008 the financial tests provided for in our partnership agreement had been met for the termination of the subordination period. As a result of the termination on February 19, 2008, all of the 7,000,000 subordinated units owned by four affiliates of Williams converted to common units on a one-for-one basis.
Results of Operations - Cash Flows
Williams Partners L.P.
Net cash provided by operating activities increased $23.3 million in 2007 as compared to 2006 due primarily to:
•
$53.9 million from changes in working capital excluding accrued interest. Cash provided by working capital increased due primarily to $25.4 million in lower accounts receivable and $31.5 million in higher accounts payable between periods; and
•
$14.2 million higher distributions related to the equity earnings of Discovery.
Partially offsetting these increases were $33.2 million in higher cash interest payments for the interest on our $750.0 million senior unsecured notes issued in 2006 to finance our acquisition of Four Corners and $11.5 million lower operating income excluding non- cash items.
The $11.5 million increase in net cash provided by operating activities for 2006 as compared to 2005 is due primarily to $23.9 million increase in operating income as adjusted for non-cash items and a $10.8 million increase in distributed earnings from Discovery, partially offset by a $23.2 million increase in cash used for working capital. The increase in cash used for working capital was caused primarily by an increase in affiliate receivables as a result of Four Corners’ transition from Williams’ cash management program to our cash management program in addition to other changes in accounts payable.
Net cash used by investing activities in 2007 includes the purchase of the Wamsutter Ownership Interests on December 11, 2007 and the additional 20% ownership interest in Discovery on June 28, 2007. Since these ownership interests were purchased from Williams, the transactions were between entities under common control, and have been accounted for at historical cost. Therefore the amount reflected as cash used by investing activities for these purchases represents the historical cost to Williams. Additionally, net cash used by investing activities in 2007, 2006 and 2005 includes maintenance and expansion capital expenditures primarily for well connects in our Four Corners business, the installation of cavern liners, and KDHE-related cavern compliance with the installation of wellhead control equipment and well meters in our NGL Services segment.
Net cash used by investing activities in 2006 relates primarily to the $607.5 million acquisition of Four Corners. Because Four Corners was an affiliate of Williams at the time of these acquisitions, these transactions are accounted for as a combination of entities under common control and the acquisition is recorded at historical cost rather than the actual consideration paid to Williams. Net cash used by investing activities in 2005 includes our capital contribution of $24.4 million to Discovery for construction of the Tahiti pipeline lateral expansion project.
Net cash provided by financing activities in 2007 includes:
•
$265.9 million of net proceeds from debt and equity issuances related to our acquisition of the Wamsutter Ownership Interest less the related amounts distributed to Williams in excess of Wamsutter’s contributed basis;
•
distributions to unitholders and our general partner of $87.3 million; and
•
contributions from our general partner to maintain its 2% ownership following the issuances of equity and per the omnibus agreement that totaled $15.7 million.
Net cash provided by financing activities in 2006 includes:
•
$624.5 million of net proceeds from debt and equity issuances related to our acquisition of Four Corners less the related amounts distributed to Williams in excess of Four Corners’ contributed basis;
•
distributions to unitholders and our general partner of $30.0 million; and
•
contributions from our general partner to maintain its 2% ownership following the issuances of equity and per the omnibus agreement that totaled $25.5 million.
Net cash provided by financing activities in 2005 includes the cash flows related to our IPO in August 2005. In addition, 2006 and 2005 included $114.5 million and $187.2 million, respectively, related to the pass through of net cash flows to Williams under its cash management program of Four Corners’ net cash flows and operations prior to our IPO.
Wamsutter - 100%
The $9.9 million increase in net cash provided by operating activities in 2007 as compared to 2006 is due primarily to $19.3 million increase in operating income, as adjusted for non-cash expenses, partially offset by $9.4 million lower cash provided from changes in working capital.
The $19.6 million increase in net cash provided by operating activities in 2006 as compared to 2005 is due primarily to a $23.0 million increase in operating income, as adjusted for non-cash expenses, partially offset by $3.4 million lower cash provided from changes in working capital.
Net cash used by investing activities in 2007, 2006 and 2005 is primarily comprised of capital expenditures related to the connection of new wells, the number of which increased significantly in 2005 and 2006. Additionally, in 2006 and 2005 there were other significant gathering system expansion projects in addition to the well connections.
Net cash used by financing activities for all periods are primarily distributions of Wamsutter’s net cash flows to Williams pursuant to its participation in Williams’ cash management program.
Discovery - 100%
Net cash provided by operating activities decreased $1.4 million in 2007 as compared to 2006 due primarily to an increase in cash used for working capital of $20.3 million, substantially offset by an increase of $19.0 million in operating income as adjusted for non-cash items.
Net cash provided by operating activities increased $32.6 million in 2006 as compared to 2005 due primarily to an increase of $22.6 million in cash provided from working capital and an increase of $10.0 million in operating income as adjusted for non-cash items. The 2006 increase in cash provided related to working capital was due to receipts on invoices that were outstanding at the end of 2005 and the collection of hurricane-related insurance receivables.
Net cash used by investing activities included $29.1 million and $32.9 million of capital spending in 2007 and 2006, respectively. These expenditures were primarily for the Tahiti project, partially offset by the use of $22.6 million and $15.8 million of Tahiti-related restricted cash in 2007 and 2006, respectively. During 2005, net cash used by investing activities included $44.6 million to fund escrow accounts for the Tahiti pipeline lateral project and related interest income and $21.4 million of capital expenditures for (1) the completion of the Front Runner and market expansion projects, (2) the initial expenditures for the Tahiti project, and (3) the purchase of leased compressors at the Larose processing plant.
Net cash used by financing activities in 2007 is almost entirely related to normal cash distributions to Discovery’s members. Net cash used by financing activities in 2006 includes $13.5 million of capital contributions compared to $43.6 million in 2005. These contributions related to the Tahiti pipeline lateral expansion. Additionally, Discovery distributed $43.6 million to its members during 2006. During 2005, Discovery distributed $43.8 million associated with its operations prior to our IPO and a $3.2 million quarterly distribution to members in the fourth quarter of 2005.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2007, is as follows (in thousands):
(a)
The assumed interest rate on our $250.0 million term loan is based on the forecasted forward LIBOR plus the applicable margin.
(b)
Includes the open purchase orders in the amount of $29.3 million as of December 31, 2007 to be paid in 2008 and product purchase and service agreements in the amount of $24.6 million as of December 31, 2007 to be paid in 2008.
(c)
Year 2013 represents one year of payments associated with an operating agreement whose term is tied to the life of the underlying gas reserves.
Our equity investee, Wamsutter, also has contractual obligations for which we are not contractually liable. These contractual obligations, however, will impact Wamsutter’s ability to make cash distributions to us. A summary of Wamsutter’s total contractual obligations as of December 31, 2007, is as follows (in thousands):
(a)
Includes the open purchase orders as of December 31, 2007 to be paid in 2008.
Our equity investee, Discovery, also has contractual obligations for which we are not contractually liable. These contractual obligations, however, will impact Discovery’s ability to make cash distributions to us. A summary of Discovery’s total contractual obligations as of December 31, 2007, is as follows (in thousands):
Effects of Inflation
We have experienced increased costs in recent years due to the effects of growth in the oil and gas industry, which has increased competition for resources. Approximately 50% and 54% of Four Corners’ and Wamsutter’s respective gathering and processing revenues are from contracts that include escalation clauses that provide for an annual escalation based on an inflation-sensitive index. These escalations, combined with increased fees where competition permits for new and amended contracts, help to offset these inflationary pressures; however, they may not always approximate the actual inflation rate we experience due to geographic and/or industry-specific inflationary pressures on our costs and expenses. We have significant annual capital expenditures related to well connections and gathering system expansions necessary to connect new sources of throughput to these systems as throughput volumes from existing wells will naturally decline over time.
Regulatory Matters
Discovery’s natural gas pipeline transportation is subject to rate regulation by the FERC under the Natural Gas Act. For more information on federal and state regulations affecting our business, please read “Risk Factors” and “FERC Regulation” elsewhere in this report.
Environmental
We are a participant in certain hydrocarbon removal and groundwater monitoring activities associated with certain well sites in New Mexico. Of nine remaining active sites, contaminants are now present at only five sites. Monitoring will continue at all sites as necessary to document monitored natural attenuation and free product will be recovered as practicable. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to eight years. As of December 31, 2007, we had accrued liabilities totaling $0.7 million for these environmental activities. Actual costs incurred will depend on the actual number of
contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities and other factors.
On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation to Four Corners that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. The NMED proposed a penalty of approximately $3 million. We are discussing the basis for and the scope of the proposed penalty with the NMED.
Our Conway storage facilities are subject to strict environmental regulation by the Underground Hydrocarbon Storage Unit within the Geology Section of the Bureau of Water of the KDHE under the Underground Hydrocarbon Storage Program, which became effective in 2003. We are in the process of modifying our Conway storage facilities, including the caverns and brine ponds, and we expect our storage operations will be in compliance with the Underground Hydrocarbon and Natural Gas Storage Program regulations by the applicable required compliance dates. In response to these increased costs, we raised our storage rates by an amount sufficient to preserve our margins in this business. Accordingly, we do not believe that these increased costs have had a material effect on our business or results of operations. We expect on average to complete workovers on each of our caverns every five to ten years and install double liners on each of our brine ponds every 18 years.
In 2004, we purchased an insurance policy that covers up to $5 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs, for these projects to the extent such costs exceed a $4.2 million deductible. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25 million. We do not expect to submit any claims under this insurance policy prior to its expected expiration date on April 30, 2008. In addition, under an omnibus agreement with Williams entered into at the closing of the IPO, Williams has agreed to indemnify us for the $4.2 million deductible (less amounts expended prior to the closing of the IPO) of remediation expenditures not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14 million cap on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy. There is also a three-year time limitation from the IPO closing date of August 23, 2005. At December 31, 2007, we had accrued liabilities totaling $3.3 million for these costs. Actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.
In connection with our operations at the Conway facilities, we are required by the KDHE regulations to provide assurance of our financial capability to plug and abandon the wells and abandon the brine facilities we operate at Conway. Williams has posted a letter of credit on our behalf in the amount of $18.3 million to guarantee our plugging and abandonment responsibilities for these facilities. We anticipate providing assurance in the form of letters of credit in future periods until such time as we obtain an investment-grade credit rating or are capable of meeting KDHE financial strength tests. After our filing of this Annual Report on Form 10-K, we will request the state to accept a financial test in lieu of the letters of credit.
In connection with the construction of Discovery’s pipeline, approximately 73 acres of marshland was traversed. Discovery is required to restore marshland in other areas to offset the damage caused during the initial construction. In Phase I of this project, Discovery created new marshlands to replace about half of the traversed acreage. Phase II, which will complete the project, began during 2005 and will cost approximately $2.9 million.
Item 7A.
Item 7A.
Qualitative and Quantitative Disclosures About Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk and interest rate risk.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of natural gas liquids and natural gas, as well as other market factors, such as market volatility and commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts. We manage a portion of the risks associated with these market fluctuations using various derivative contracts. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio.
Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95% probability that the one-day loss in fair value of the portfolio will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
Our derivative contracts are contracts held for nontrading purposes that hedge a portion of our commodity price risk exposure from natural gas liquid sales and natural gas purchases. Certain of our derivative contracts have been designated as normal purchases or sales under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and, therefore, have been excluded from our estimation of value at risk.
The value at risk for our derivative contracts was $1.0 million at December 31, 2007. We had no derivative contracts at December 31, 2006.
All of the derivative contracts included in our value-at-risk calculation are accounted for as cash flow hedges under SFAS No. 133. Any change in the fair value of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. A majority of our current debt portfolio is comprised of fixed interest rate debt which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit agreements would be at a variable interest rate and would expose us to the risk of increasing interest rates.
The tables below provide information about our interest rate-sensitive instruments as of December 31, 2007 and 2006. Long-term debt in the table represents principal cash flows by expected maturity date. The fair value of our private debt is valued based on the prices of similar securities with similar terms and credit ratings.
(1)
The weighted-average interest rate for 2007 is LIBOR plus 1 percent.
Item 8.
Item 8.
Financial Statements and Supplementary Data
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Our general partner 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) and for the assessment of the effectiveness of internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of Williams Partners L.P.’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on our assessment we believe that, as of December 31, 2007, Williams Partners L.P.’s internal control over financial reporting is effective based on those criteria.
Ernst & Young, LLP, our independent registered public accounting firm, has audited the effectiveness of the company’s internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited Williams Partners L.P.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Williams Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2007 and 2006, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated February 25, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2007 and 2006, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As described in Note 8, effective December 31, 2005, Williams Partners L.P. adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2008 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2008
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
*
Recast as discussed in Note 1.
See accompanying notes to consolidated financial statements.
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
*
Recast as discussed in Note 1.
(a)
Includes Class B units converted to Common on May 21, 2007.
See accompanying notes to consolidated financial statements.
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL*
*
Recast as discussed in Note 1.
See accompanying notes to consolidated financial statements.
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
*
Recast as discussed in Note 1.
See accompanying notes to consolidated financial statements.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
Organization
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Wamsutter LLC (Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to Wamsutter or Discovery by name, we are referring exclusively to their businesses and operations.
We are a Delaware limited partnership that was formed in February 2005, to acquire and own (1) a 40% interest in Discovery; (2) the Carbonate Trend gathering pipeline off the coast of Alabama; (3) three integrated natural gas liquids (NGL) product storage facilities near Conway, Kansas; and (4) a 50% undivided ownership interest in a fractionator near Conway, Kansas. Prior to the closing of our initial public offering (the IPO) in August 2005, the 40% interest in Discovery was held by Williams Energy, L.L.C. (Energy) and Williams Discovery Pipeline LLC; the Carbonate Trend gathering pipeline was held in Carbonate Trend Pipeline LLC (CTP), which was owned by Williams Mobile Bay Producers Services, L.L.C.; and the NGL product storage facilities and the interest in the fractionator were owned by Mid-Continent Fractionation and Storage, LLC (MCFS). All of these were wholly owned indirect subsidiaries of The Williams Companies, Inc. (collectively Williams). Williams Partners GP LLC, a Delaware limited liability company, was also formed in February 2005 to serve as our general partner. We also formed Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us), through which all our activities are conducted.
Initial Public Offering and Related Transactions
On August 23, 2005, we completed our IPO of 5,000,000 common units representing limited partner interests in us at a price of $21.50 per unit. The proceeds of $100.2 million, net of the underwriters’ discount and a structuring fee totaling $7.3 million, were used to:
•
distribute $58.8 million to Williams in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;
•
provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;
•
provide $12.7 million of additional working capital; and
•
pay $4.3 million of expenses associated with the IPO and related formation transactions.
Concurrent with the closing of the IPO, a 40% interest in Discovery and all of the interests in CTP and MCFS were contributed to us by Williams’ subsidiaries in exchange for an aggregate of 2,000,000 common units and 7,000,000 subordinated units. The public, through the underwriters of the offering, contributed $107.5 million ($100.2 million net of the underwriters’ discount and a structuring fee) to us in exchange for 5,000,000 common units representing a 35% limited partner interest in us. Additionally, at the closing of the IPO, the underwriters fully exercised their option to purchase 750,000 common units from Williams’ subsidiaries at the IPO price of $21.50 per unit less the underwriters’ discount and a structuring fee.
Acquisition of Four Corners
On June 20, 2006, we acquired a 25.1% membership interest in Williams Four Corners LLC (Four Corners) pursuant to an agreement with Williams Energy Services, LLC (WES), Williams Field Services Group LLC (WFSG), Williams Field Services Company, LLC (WFSC) and OLLC for aggregate consideration of $360.0 million. Prior to closing, WFSC contributed to Four Corners its natural gas gathering, processing and treating assets in the San Juan Basin in New Mexico and Colorado. We financed this acquisition with a combination of equity and debt. On June 20, 2006, we issued 6,600,000 common units at a price of $31.25
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
per unit. Additionally, at the closing, the underwriters fully exercised their option to purchase 990,000 common units at a price of $31.25 per unit. This offering yielded net proceeds of $227.1 million after payment of underwriting discounts and commissions of $10.1 million but before the payment of other offering expenses. On June 20, 2006, we also issued $150.0 million aggregate principal of unsecured 7.5% senior notes due 2011 under a private placement debt agreement. Proceeds from this issuance totaled $146.8 million (net of $3.2 million of related expenses).
On December 13, 2006, we acquired the remaining 74.9% membership interest in Four Corners pursuant to an agreement with WES, WFSG, WFSC and OLLC for aggregate consideration of $1.223 billion. We financed this acquisition with a combination of equity and debt. On December 13, 2006, we issued 7,000,000 common units at a price of $38.00. Additionally, at the closing, the underwriters fully exercised their option to purchase 1,050,000 common units at a price of $38.00 per unit. This offering yielded net proceeds of $293.7 million after payment of underwriting discounts and commissions of $12.2 million but before the payment of other offering expenses. On December 13, 2006, we received $346.5 million in proceeds from the sale of 2,905,030 common units and 6,805,492 unregistered Class B units in a private placement net of $3.5 million in placement agency fees. On December 13, 2006, we also issued $600.0 million aggregate principal of unsecured 7.25% senior notes due 2017 under a private placement debt agreement. Proceeds from this issuance totaled $590.0 million (net of $10.0 million of related expenses).
Because Four Corners was an affiliate of Williams at the time of these acquisitions, these transactions were accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of Four Corners were combined with Williams Partners L.P. at their historical amounts for all periods presented. These acquisitions did not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
Additional Investment in Discovery
On June 28, 2007, we closed on the acquisition of an additional 20% interest in Discovery from Energy and WES for aggregate consideration of $78.0 million, bringing our total ownership of Discovery to 60%. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly our consolidated financial statements and notes reflect the combined historical results of our investment in Discovery throughout the periods presented. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment. The effect of recasting our financial statements to account for this common control exchange increased net income $2.6 million, $6.0 million and $3.5 million for 2007, 2006 and 2005, respectively. The acquisition had no impact on earnings per unit as pre-acquisition earnings were allocated to the general partner.
Acquisition of Wamsutter
On December 11, 2007, we acquired the ownership interests in Wamsutter, consisting of 100% of the Class A limited liability company interests and 20 Class C units representing 50% of the initial Class C ownership interests (collectively the Wamsutter Ownership Interests) in exchange for aggregate consideration of $750.0 million. We financed this acquisition with a combination of equity and debt. On December 11, 2007, we issued 9,250,000 common units at a price of $37.75 per unit. This offering yielded net proceeds of $335.2 million after payment of underwriting discounts and commissions of $14.0 million but before the payment of other offering expenses. Additionally, on December 11, 2007, we issued approximately $157.2 million, or 4,163,527 common units to Williams at a price per common unit of $37.75. On December 11, 2007, we also initiated a term loan under our $450.0 million credit facility, netting proceeds of $249.1 million after
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
debt acquisition costs. Because the Wamsutter Ownership Interests were purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes reflect the combined historical results of our investment in Wamsutter throughout the periods presented. We account for this investment under the equity method due to the voting provisions of Wamsutter’s limited liability agreement which provide Williams significant participatory rights such that we do not control the investment. The effect of recasting our financial statements to account for this common control exchange increased net income $68.8 million, $61.7 million and $40.5 million for 2007, 2006 and 2005, respectively. This acquisition does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.
On January 9, 2008, we sold an additional 800,000 common units to the underwriters upon the underwriters’ partial exercise of their option to purchase additional common units. We used the net proceeds from the partial exercise of the underwriters’ option to redeem 800,000 common units from Williams at a price per common unit of $36.24 ($37.75, net of underwriter discount).
Note 2.
Description of Business
We are principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing NGLs. Operations of our businesses are located in the United States and are organized into three reporting segments: (1) Gathering and Processing-West, (2) Gathering and Processing-Gulf and (3) NGL Services. Our Gathering and Processing-West segment includes the Four Corners gathering and processing operations and our equity investment in Wamsutter. Our Gathering and Processing-Gulf segment includes the Carbonate Trend gathering pipeline and our equity investment in Discovery. Our NGL Services segment includes the Conway fractionation and storage operations.
Gathering and Processing-West. Our Four Corners natural gas gathering, processing and treating assets consist of, among other things, (1) a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with a capacity of two billion cubic feet per day, (2) the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 million cubic feet per day (MMcf/d) and (3) the Milagro and Esperanza natural gas treating plants in New Mexico, which have a combined carbon dioxide treating capacity of 750 MMcf/d.
Wamsutter owns an approximate 1,700-mile natural gas gathering system in the Washakie Basin in south-central Wyoming that currently connects approximately 1,720 wells, with a typical operating capacity of approximately 500 MMcf/d at current operating pressures, and the Echo Springs cryogenic processing plant near Wamsutter, Wyoming which has 390 MMcf/d of inlet cryogenic processing capacity and NGL production capacity of 30,000 bpd.
Gathering and Processing-Gulf . We own a 60% interest in Discovery, which includes a wholly-owned subsidiary, Discovery Gas Transmission LLC. Discovery owns (1) a 283-mile natural gas gathering and transportation pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, (2) a 600 MMcf/d cryogenic natural gas processing plant in Larose, Louisiana, (3) a 32,000 barrels per day (bpd) natural gas liquids fractionator in Paradis, Louisiana and (4) a 22-mile mixed NGL pipeline connecting the gas processing plant to the fractionator. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such. Hence, this equity investment is considered part of the Gathering and Processing-Gulf segment.
Our Carbonate Trend gathering pipeline is an unregulated sour gas gathering pipeline consisting of approximately 34 miles of pipeline off the coast of Alabama.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NGL Services. Our Conway storage facilities include three underground NGL storage facilities in the Conway, Kansas, area with a storage capacity of approximately 20 million barrels. The facilities are connected via a series of pipelines. The storage facilities receive daily shipments of a variety of products, including mixed NGLs and fractionated products. In addition to pipeline connections, one facility offers truck and rail service.
Our Conway fractionation facility is located near Conway, Kansas, and has a capacity of approximately 107,000 bpd. We own a 50% undivided interest in these facilities representing capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK Partners, L.P. are the other owners. Williams operates the facility pursuant to an operating agreement that extends until May 2011. The fractionator separates mixed NGLs into five products: ethane, propane, normal butane, isobutane and natural gasoline. Portions of these products are then transported and stored at our Conway storage facilities.
Note 3.
Summary of Significant Accounting Policies
Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of the parent and our wholly owned subsidiaries. Intercompany accounts and transactions have been eliminated. Certain amounts have been reclassified to conform to the current classifications.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated 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:
•
loss contingencies;
•
impairment assessments of long-lived assets;
•
environmental remediation obligations; and
•
asset retirement obligations.
These estimates are discussed further throughout the accompanying notes.
Proportional Accounting for the Conway Fractionator. No separate legal entity exists for the fractionator. We hold a 50% undivided interest in the fractionator property, plant and equipment, and we are responsible for our proportional share of the costs and expenses of the fractionator. As operator of the facility, we incur the liabilities of the fractionator (except for certain fuel costs purchased directly by one of the co-owners) and are reimbursed by the co-owners for their proportional share of the total costs and expenses. Each co-owner is responsible for the marketing of their proportional share of the fractionator’s capacity. Accordingly, we reflect our proportionate share of the revenues and costs and expenses of the fractionator in the Consolidated Statements of Income, and we reflect our proportionate share of the fractionator property, plant and equipment in the Consolidated Balance Sheets. Liabilities in the Consolidated Balance Sheets include those incurred on behalf of the co-owners with corresponding receivables from the co-owners. Accounts receivable also includes receivables from our customers for fractionation services.
Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue which generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.
Gas Purchase Contract. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. The gas purchase contract was for the purchase of 80,000 MMBtu per month and terminated on December 31, 2007. The initial value of this contract was amortized to expense over the contract life.
Reimbursable Projects. Expenditures incurred for the repair of the Ignacio natural gas processing plant damaged by a fire in November 2007, which are probable of recovery when incurred, are recorded as reimbursable projects. Expenditures up to the insurance deductible and amounts subsequently determined not to be recoverable are expensed.
Investments. We account for our Wamsutter Ownership Interests and our 60% investment in Discovery under the equity method due to the voting provisions of their limited liability company agreements which provide the other members of these entities significant participatory rights such that we do not control these investments. In 2004, we recognized an other-than-temporary impairment of our Discovery investment. As a result, Discovery’s underlying equity exceeds the carrying value of our investment at December 31, 2007 and 2006.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided on the straight-line basis over estimated useful lives. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that enhance the functionality or extend the useful lives of the assets are capitalized. The cost of property, plant and equipment sold or retired and the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recorded in the Consolidated Statements of Income.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense.
Prepaid Expenses and Leasing Activities. Prepaid expenses include the unamortized balance of minimum lease payments made to date under a right-of-way renewal agreement. Land and right-of-way lease payments made at the time of initial construction or placement of plant and equipment on leased land are capitalized as part of the cost of the assets. Lease payments made in connection with subsequent renewals or amendments of these leases are classified as prepaid expenses. The minimum lease payments for the lease term, including any renewal are expensed on a straight-line basis over the lease term.
Product Imbalances. In the course of providing gathering, processing and treating services to our customers, we realize over and under deliveries of our customers’ products and over and under purchases of shrink replacement gas when our purchases vary from operational requirements. In addition, in the course of providing gathering, processing, treating, fractionation and storage services to our customers, we realize gains and losses due to (1) the product blending process at the Conway fractionator, (2) the periodic emptying of
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
storage caverns at Conway and (3) inaccuracies inherent in the gas measurement process. These gains and losses impact our results of operations and are included in operating and maintenance expense in the Consolidated Statements of Income. These items are reflected as product imbalance receivables and payables on the Consolidated Balance Sheets. Product imbalance receivables are valued based on the lower of current market prices or current cost of natural gas in the system or in the case of our Conway facilities, lower of the current market prices or weighted average value of NGLs. Product imbalance payables are valued at current market prices. The majority of Four Corners’ settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances build up over a period of time and are ultimately settled in cash and are generally negotiated at values which approximate average market prices over a period of time. These gains and losses impact our results of operations and are included in operating and maintenance expense in the Consolidated Statements of Income.
Derivative Instruments and Hedging Activities. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swap agreements and forward contracts involving short- and long-term purchases and sales of a physical energy commodity. The counterparty to these instruments is a Williams affiliate. We execute these transactions in over-the-counter markets in which quoted prices exist for active periods. We report the fair value of derivatives, except for those which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheets in other current assets, other accrued liabilities, other assets or other noncurrent liabilities. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual contracts.
The accounting for changes in the fair value of derivatives is governed by Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and depends on whether the derivative has been designated in a hedging relationship and what type of hedging relationship it is. The accounting for the change in fair value can be summarized as follows:
We have elected the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet since we made the election of this exception at the inception of these contracts.
For a derivative to qualify for designation in a hedging relationship it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in other revenues.
For derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in other comprehensive loss and reclassified into product sales revenues in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in product sales revenues. Gains or losses deferred in accumulated other comprehensive
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
loss associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive loss until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in accumulated other comprehensive loss is recognized in other revenues at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.
Revenue Recognition. The nature of our businesses results in various forms of revenue recognition. Our Gathering and Processing segments recognize (1) revenue from the gathering and processing of gas in the period the service is provided based on contractual terms and the related natural gas and liquid volumes and (2) product sales revenue when the product has been delivered. Our NGL Services segment recognizes (1) fractionation revenues when services have been performed and product has been delivered, (2) storage revenues under prepaid contracted storage capacity evenly over the life of the contract as services are provided and (3) product sales revenue when the product has been delivered.
Impairment of Long-Lived Assets and Investments. We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The impairment evaluation of tangible long-lived assets is measured pursuant to the guidelines of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value of the assets is recoverable. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.
Judgments and assumptions are inherent in our 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.
Environmental. Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing contamination caused by past operations that do not contribute to current or future revenue generation are expensed. Accruals related to environmental matters are generally determined based on site-specific plans for remediation, taking into account our prior remediation experience. Environmental contingencies are recorded independently of any potential claim for recovery.
Capitalized Interest. We capitalize interest on major projects during construction based on our average interest rate on debt to the extent we incur interest expense. Prior to our IPO, Williams provided the financing for capital expenditures; hence, the rates used to calculate the interest were based on Williams’ average interest rate on debt during the applicable period in time. Capitalized interest for the periods presented is immaterial.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of 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 our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.
Earnings Per Unit. In accordance with SFAS No. 128, “Earnings Per Share,” as clarified by the Emerging Issues Task Force (EITF) Issue 03-6, we use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common, Class B and subordinated units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.
Recent Accounting Standards. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements.” This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In December 2007, the FASB issued proposed FASB Staff Position (FSP) No. FAS 157-b deferring the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. On January 1, 2008, we adopted SFAS No. 157 applying a prospective transition for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact to our Consolidated Financial Statements. SFAS No. 157 expands disclosures about assets and liabilities measured at fair value on a recurring basis effective beginning with the first quarter of 2008 reporting.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115.” SFAS No. 159 establishes a fair value option permitting entities to elect to measure eligible financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, is irrevocable and is applied only to the entire instrument. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007, and should not be applied retrospectively to fiscal years beginning prior to the effective date. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. Subsequent to January 1, 2008, the fair value option can only be elected when a financial instrument or certain other item is entered into. On January 1, 2008, we adopted SFAS No. 159 but have not elected the fair value option for any existing eligible financial instruments or other items.
In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations.” SFAS No. 141(R) applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, the liabilities assumed, noncontrolling interest in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100% ownership interest in the acquiree. SFAS No. 141(R) also requires expensing of transaction costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
financial effects of the business combination. SFAS No. 141(R) is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008.
Note 4.
Allocation of Net Income and Distributions
The allocation of net income between our general partner and limited partners, as reflected in the Consolidated Statement of Partners’ Capital, for the years ended December 31, 2007 and 2006 are as follows (in thousands):
*
Under the “two class” method of computing earnings per share, prescribed by SFAS No. 128, “Earnings Per Share,” earnings are to be allocated to participating securities as if all of the earnings for the period had been distributed. As a result, the general partner receives an additional allocation of income in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. The assumed incentive distribution for the years ended December 31, 2007 and 2006 was $8.4 million and $0.4 million, respectively. There were no assumed incentive distributions during 2005.
Pursuant to the partnership agreement, income allocations are made on a quarterly basis; therefore, earnings per limited partner unit for each year is calculated as the sum of the quarterly earnings per limited partner unit for each of the four quarters in the year. Common and subordinated unitholders share equally, on a per-unit basis, in the net income allocated to limited partners.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The reimbursable general and administrative and core drilling costs represent the costs charged against our income that are required to be reimbursed to us by our general partner under the terms of the omnibus agreement.
We paid or have authorized payment of the following cash distributions during 2005, 2006 and 2007 (in thousands, except for per unit amounts):
(a)
This distribution represents the $0.35 per unit minimum quarterly distribution pro-rated for the 39-day period following the IPO closing date (August 23, 2005 through September 30, 2005).
(b)
On February 14, 2008, we paid a cash distribution of $0.575 per unit on our outstanding common and subordinated units to unitholders of record on February 7, 2008.
Note 5.
Related Party Transactions
The employees of our operated assets and all of our general and administrative employees are employees of Williams. Williams directly charges us for the payroll costs associated with the operations employees. Williams carries the obligations for most employee-related benefits in its financial statements, including the liabilities related to the employee retirement and medical plans and paid time off. Certain of the payroll costs associated with the operations employees are charged back to the other Conway fractionator co-owners. Our share of those costs are charged to us through affiliate billings and reflected in Operating and maintenance expense - Affiliate in the accompanying Consolidated Statements of Income.
We are charged for certain administrative expenses by Williams and its Midstream segment of which we are a part. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams and Midstream at our request. Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are allocated to us. These allocated corporate administrative expenses are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of direct and allocated administrative expenses is reflected in General and administrative expense - Affiliate in the accompanying Consolidated Statements of Income. 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. Under the omnibus agreement, Williams gives us a quarterly credit for general and administrative expenses. These amounts are reflected as a capital contribution from our general partner. The annual amounts of the credits are as follows: $3.9 million in 2005 ($1.4 million pro-rated for the portion of the year from
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
August 23 to December 31), $3.2 million in 2006, $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009.
At December 31, 2007 and 2006 we have a contribution receivable from our general partner of $0.5 million and $0.4 million, respectively, for amounts reimbursable to us under the omnibus agreement. This receivable is netted against Partners’ capital on the Consolidated Balance Sheets.
We purchase natural gas for shrink replacement and fuel for Four Corners and the Conway fractionator, including fuel on behalf of the Conway co-owners, from Williams Gas Marketing, Inc. (WGM), a wholly owned subsidiary of Williams. Natural gas purchased for fuel is reflected in Operating and maintenance expense - Affiliate, and natural gas purchased for shrink replacement is reflected in Product cost and shrink replacement - Affiliate in the accompanying Consolidated Statements of Income. These purchases are generally made at market rates at the time of purchase. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. The amortization of this contract is reflected in Operating and maintenance expense - Affiliate in the accompanying Consolidated Statements of Income. The carrying value of this contract is reflected as Gas purchase contract - affiliate on the Consolidated Balance Sheets. This contract terminated on December 31, 2007. In December 2007, we entered into fixed price natural gas purchase contracts with WGM to hedge the price of a portion of our natural gas shrink replacement costs for February through December of 2008.
Four Corners uses waste heat from a co-generation plant located adjacent to the Milagro treating plant. The co-generation plant is owned by an affiliate of Williams, Williams Flexible Generation, LLC. Waste heat is required for the natural gas treating process, which occurs at Milagro. The charge to us for the waste heat is based on the natural gas needed to generate the waste heat. We purchase this natural gas from WGM. The natural gas cost charged to us by WGM has been favorably impacted by WGM’s fixed price natural gas fuel contracts. This cost is reflected in Operations and maintenance expense - Affiliate. This impact was approximately $9.0 million annually during 2006 and 2005 as compared to estimated market prices. These agreements expired in the fourth quarter of 2006. Milagro natural gas fuel costs have increased since the expiration of these agreements, due to market prices exceeding prices associated with these prior agreements.
The operation of the Four Corners gathering system includes the routine movement of gas across gathering systems. We refer to this activity as “crosshauling.” Crosshauling typically involves the movement of some natural gas between gathering systems at established interconnect points to optimize flow, reduce expenses or increase profitability. As a result, we must purchase gas for delivery to customers at certain plant outlets and we have excess volumes to sell at other plant outlets. These purchase and sales transactions are conducted for us by WGM at current market prices at each location and are included in Product sales - Affiliate and Product cost and shrink replacement - Affiliate on the Consolidated Statements of Income. Historically, WGM has not charged us a fee for providing this service, but has occasionally benefited from price differentials that historically existed from time to time between the plant outlets.
We sell the NGLs to which we take title on the Four Corners system to Williams NGL Marketing LLC (WNGLM), a wholly owned subsidiary of Williams. Revenues associated with these activities are reflected as Product sales - Affiliate on the Consolidated Statements of Income. These transactions are conducted at current market prices for the products.
We enter into financial swap contracts with WGM and WNGLM to hedge forecasted NGL sales. These contracts are priced based on market rates at the time of execution and are reflected in Derivative assets - affiliate and Derivative liabilities - affiliate on the Consolidated Balance Sheet.
One of our major customers is Williams Production Company (WPC), a wholly owned subsidiary of Williams. WPC is one of the largest natural gas producers in the San Juan Basin and we provide natural gas gathering, treating and processing services to WPC under several contracts. One of the contracts with WPC is
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
adjusted annually based on changes in the average price of natural gas. Revenues associated with these activities are reflected in the Gathering and processing - Affiliate on the Consolidated Statements of Income.
We sell Conway’s surplus propane and other NGLs to WGM, which takes title to the product and resells it, for its own account, to end users. Revenues associated with these activities are reflected as Product sales - Affiliate on the Consolidated Statements of Income. Correspondingly, we purchase ethane and other NGLs for Conway from WGM to replenish deficit product inventory positions. The transactions conducted between us and WGM are transacted at current market prices for the products.
Prior to its acquisition by us, Four Corners participated in Williams’ cash management program under an unsecured promissory note agreement with Williams for both advances to and from Williams. As of December 31, 2005, Four Corners’ net advances to Williams were classified as a component of general partner’s capital because Williams has not historically required repayment or repaid amounts owed us. In addition, upon Four Corners’ acquisition by us, the outstanding advances were distributed to Williams. Changes in these advances to Williams are presented as distributions to Williams in the Consolidated Statement of Partners’ Capital and Consolidated Statements of Cash Flows.
For 2007, 2006, and 2005 affiliate interest expense includes commitment fees on the working capital credit facility (see Note 11). For 2005, affiliate interest expense also includes interest on the advances with Williams calculated using Williams’ weighted average cost of debt applied to the outstanding balance of the advances with Williams. The interest rate on the advances with Williams was 7.70% at December 31, 2005.
With the transition to a stand-alone cash management program, amounts owed by us or to us by Williams or its subsidiaries are shown as Accounts receivable - Affiliate or Accounts payable - Affiliate in the accompanying Consolidated Balance Sheets.
Note 6.
Equity Investments
Wamsutter
Our Wamsutter Ownership Interests are accounted for using the equity method of accounting due to the voting provisions of Wamsutter’s limited liability company agreement which provide the other member, owned by a Williams affiliate, significant participatory rights such that we do not control the investment.
Williams is the operator of Wamsutter. As such, effective December 1, 2007, Williams is reimbursed on a monthly basis for all direct and indirect expenses it incurs on behalf of Wamsutter including Wamsutter’s allocable share of general and administrative costs.
Wamsutter participates in Williams’ cash management program. Therefore, Wamsutter carries no cash balances. Pursuant to their LLC Agreement, Wamsutter has made net advances to Williams, which were classified as a component of their members’ capital because although the advances are due on demand, Williams has not historically required repayment or repaid amounts owed to Wamsutter.
The Wamsutter LLC Agreement provides for distributions of available cash to be made quarterly beginning in March 2008. Available cash is defined as cash generated from Wamsutter’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law and or debt instrument or other agreement to which it is a party.
Wamsutter will distribute its available cash as follows:
•
First, an amount equal to $17.5 million per quarter to the holder of the Class A membership interests. We currently own 100% of the Class A interests;
•
Second, an amount equal to the amount the distribution on the Class A membership interests in prior quarters of the current distribution year was less than $17.5 million per quarter to the holder of the Class A membership interests; and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
•
Third, 5% of remaining available cash shall be distributed to the holder of the Class A membership interests and 95% shall be distributed to the holders of the Class C units, on a pro rata basis. We currently own 50% of the Class C units.
In addition, to the extent that at the end of the fourth quarter of a distribution year, the Class A member has received less than $70.0 million under the first and second bullets above, the Class C members will be required to repay any distributions they received in that distribution year such that the Class A member receives $70.0 million for that distribution year. If this repayment is insufficient to result in the Class A member receiving $70.0 million, the shortfall will not carry forward to the next distribution year. The initial distribution year for Wamsutter commenced on December 1, 2007 and ends on November 30, 2008. Subsequent distribution years for Wamsutter will commence on December 1 and end on November 30.
We will be allocated net income by Wamsutter based upon the allocation and distribution provisions of their LLC Agreement. In general, the agreement allocates income to the Class A, B and C ownership interests in a manner that will maintain capital account balances reflective of the amounts each ownership interest would receive if Wamsutter were dissolved and liquidated at carrying value. In general, pursuant to those provisions, income allocations follow the provisions of the LLC agreement for the distribution of available cash.
Wamsutter’s LLC agreement provides each quarter during 2008 through 2012, that it receive a transition support payment, related to a cap on general and administrative expenses, from its Class B ownership interest. This payment will be distributed directly to our Class A ownership interest. The reimbursement will be treated as a capital contribution by its Class B member and the cost subject to this reimbursement will be allocated entirely to its Class B member.
The summarized financial position and results of operations for 100% of Wamsutter are presented below (in thousands).
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Discovery Producer Services
Our 60% investment in Discovery is accounted for using the equity method of accounting due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment.
Williams is the operator of Discovery. Discovery reimburses Williams for actual payroll and employee benefit costs incurred on its behalf. In addition, Discovery pays Williams a monthly operations and management fee to cover the cost of accounting services, computer systems and management services provided to it. Discovery also has an agreement with Williams pursuant to which (1) Discovery purchases a portion of the natural gas from Williams to meet its fuel and shrink replacement needs at its processing plant and (2) Williams purchases the NGLs and excess natural gas to which Discovery takes title.
As discussed in Note 1. Organization, our consolidated financial statements and notes reflect the additional 20% interest in Discovery which we acquired in mid-2007. However, certain cash transactions that occurred between Discovery and Williams prior to this acquisition that related to the additional 20% interest are not reflected in our Consolidated Statements of Cash Flows even though these transactions affect the carrying value of our investment in Discovery. These transactions were omitted from our Consolidated Statements of Cash Flows because they did not affect our cash. The total of these transactions is reflected as an adjustment in the basis of our investment in Discovery on our Consolidated Statement of Partners’ Capital. A summary of these transactions is as follows (in thousands):
In October 2006 and September 2005, we made $1.6 million and $24.4 million capital contributions, respectively, to Discovery for a substantial portion of our then 40% share of the estimated future capital expenditures for the Tahiti pipeline lateral expansion project.
During 2007, 2006, and 2005 we received total distributions of $35.5 million, $16.4 million, and $1.3 million, respectively, from Discovery for the 60% interest we currently own or the 40% interest we owned at the time of distribution.
The summarized financial position and results of operations for 100% of Discovery are presented below (in thousands).
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 7.
Other (Income) Expense
Other (income) expense - net reflected on the Consolidated Statements of Income consists of the following items:
Impairment of Carbonate Trend Pipeline. During the fourth quarter of 2007, we determined that the carrying value of this pipeline, included in our Gathering and Processing - Gulf segment, may not be recoverable because of forecasted declining cash flows. As a result, we recognized an impairment charge of $10.4 million to reduce the carrying value to management’s estimate of fair value at December 31, 2007. We estimated fair value using market multiples and discounted cash flow projections.
LaMaquina Carbon Dioxide Treating Facility. This Four Corners facility consisted of two amine trains and seven gas powered generator sets. The facility was shut down in 2002 due to a reduced need for treating. In 2003, management estimated that only one amine train would be returned to service. As a result, we recognized an impairment of the carrying value of the other train to its estimated fair value based on estimated salvage values and sales prices. Further developments in 2004 led management to conclude that the facility would not return to service. Thus, we recognized an additional impairment of the carrying value to management’s estimate of fair value. The facility was sold in the first quarter of 2006 resulting in the recognition of a gain on the sale in 2006.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 8.
Property, Plant and Equipment
Property, plant and equipment, at cost, is as follows:
Effective December 31, 2005, we adopted FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $1.4 million equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $0.1 million increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $1.3 million reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. An additional $0.1 million reduction of earnings is reflected as a cumulative effect of a change in accounting principle for our 60% interest in Discovery’s cumulative effect of a change in accounting principle related to the adoption of FIN No. 47.
Our asset retirement obligations relate to gas processing and compression facilities located on leased land, wellhead connections on federal land, underground storage caverns and the associated brine ponds and offshore pipelines. At the end of the useful life of each respective asset, we are legally or contractually obligated to remove certain surface equipment and cap certain gathering pipelines at the wellhead connections, properly abandon the storage caverns and offshore pipelines, empty the brine ponds and restore the surface, and remove any related surface equipment.
A rollforward of our asset retirement obligation for 2007 and 2006 is presented below.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 9.
Accrued Liabilities
Accrued liabilities are as follows:
Note 10.
Major Customers, Concentrations of Credit Risk, Financial Instruments and Energy Commodity Cash Flow Hedges
Major customers
Our largest customer, on a percentage of revenues basis, is Williams NGL Marketing LLC, which purchases and resells substantially all of the NGLs to which we take title. Williams NGL Marketing LLC accounted for 49%, 43%, and 46% of revenues in 2007, 2006 and 2005, respectively. The remaining largest customer, ConocoPhillips, from our Gathering and Processing - West segment, accounted for 22%, 21%, and 24% of revenues in 2007, 2006 and 2005, respectively.
Concentrations of Credit Risk
Our cash equivalents consist of high-quality securities placed with various major financial institutions with credit ratings at or above AAA by Standard & Poor’s or Aa by Moody’s Investor’s Service.
The counterparties to our derivative contracts are affiliates of Williams, which minimizes our credit risk exposure.
The following table summarizes the concentration of accounts receivable by service and segment.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
At December 31, 2007 and 2006, a substantial portion of our accounts receivable result from product sales and gathering and processing services provided to two of our customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial conditions and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollectible receivables.
Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments.
Cash and cash equivalents. The carrying amounts reported in the balance sheets approximate fair value due to the short-term maturity of these instruments.
Long-term debt. The fair value of our private long-term debt is based on the prices of similar securities with similar terms and credit ratings.
Energy commodity swap agreements. The fair value of our swap agreements is based on prices of the underlying energy commodities over the contract life and contractual or notional volumes with the resulting expected future cash flows discounted to a present value using a risk-free market interest rate.
Carrying amounts and fair values of our financial instruments
Energy Commodity Cash Flow Hedges
We are exposed to market risk from changes in energy commodity prices within our operations. Our Four Corners operation receives NGL volumes as compensation for certain processing services. To reduce our exposure to a decrease in revenues from the sale of these NGL volumes from fluctuations in NGL market prices, we entered into financial swap contracts. We designate these derivatives as cash flow hedges under SFAS No. 133. These derivatives are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. No net gains or losses from hedge ineffectiveness are included in the Consolidated Statements of Income during 2007 and 2006. For 2007 and 2006, there were no derivative gains or losses excluded from the assessment of hedge effectiveness. At December 31, 2007 we have hedged 4.2 million gallons of monthly February through December 2008 forecasted NGL sales. Based on the recorded values at December 31, 2007, approximately $2.5 million of net losses will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2007. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2008 will likely differ from these values. These gains or losses will offset net losses or gains that will be realized into earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 11.
Long-Term Debt, Credit Facilities and Leasing Activities
Long-Term Debt
Long-term debt at December 31, 2007 and 2006 is as follows:
(1)
At December 31, 2007
The terms of the senior unsecured notes are governed by indentures that contains affirmative and negative covenants that, among other things, limit (1) our ability and the ability of our subsidiaries, Discovery and Wamsutter, to incur liens securing indebtedness, (2) mergers, consolidations and transfers of all or substantially all of our properties or assets, (3) Williams Partners Finance Corporation’s, our wholly owned subsidiary organized for the sole purpose of co-issuing our debt securities, ability to incur additional indebtedness and (4) Williams Partners Finance Corporation’s ability to engage in any business not related to obtaining money or arranging financing for us or our other subsidiaries. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.
We may redeem the senior unsecured notes at our option in whole or in part at any time or from time to time prior to the respective maturity dates, at a redemption price per note equal to the sum of (1) the then outstanding principal amount thereof, plus (2) accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), plus (3) a specified “make-whole” premium (as defined in the indenture). Additionally, upon a change of control (as defined in the indenture), each holder of the senior unsecured notes will have the right to require us to repurchase all or any part of such holder’s senior unsecured notes at a price equal to 101% of the principal amount of the senior unsecured notes plus accrued and unpaid interest, if any, to the date of settlement. Except upon a change of control as described in the prior sentence, we are not required to make mandatory redemption or sinking fund payments with respect to the senior unsecured notes or to repurchase the senior unsecured notes at the option of the holders.
Pursuant to the indentures, we may issue additional notes from time to time. The senior notes and any additional notes subsequently issued under the indentures, together with any exchange notes, will be treated as a single class for all purposes under the indentures, including, without limitation, waivers, amendments, redemptions and offers to purchase.
The senior notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to all of our future indebtedness that is expressly subordinated in right of payment to the senior notes. The senior notes will not initially be guaranteed by any of our subsidiaries. In the future in certain instances as set forth in the indenture, one or more of our subsidiaries may be required to guarantee the senior notes.
Cash payments for interest during 2007, 2006 and 2005 were $38.8 million, $5.5 million and $0.3 million, respectively.
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Credit Facilities
On December 11, 2007, we entered into a $450.0 million senior unsecured credit agreement with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility available for borrowings and letters of credit and a $250.0 million term loan. Under certain conditions, the revolving credit facility may be increased up to an additional $100.0 million. Borrowings under this agreement must be repaid by December 11, 2012. At December 31, 2007, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding under the revolving credit facility.
Interest on borrowings under this agreement will be payable at rates per annum equal to, at our option: (1) a fluctuating base rate equal to Citibank, N.A.’s prime rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The applicable margin spread and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings.
The credit agreement contains various covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur indebtedness, grant certain liens supporting indebtedness, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of our assets, make certain transfers, enter into certain affiliate transactions, make distributions or other payments other than distributions of available cash under certain conditions, or use proceeds other than for partnership purposes (not to include the purchase or carrying of margin stock). Significant financial covenants under the credit agreement include the following:
•
We together with our consolidated subsidiaries and Wamsutter, are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA (each as defined in the credit agreement) of no greater than 5.00 to 1.00. This ratio may be increased in the case of an acquisition of $50.0 million or more, in which case the ratio will be 5.50 to 1.00 for the three fiscal quarter-periods following such acquisition.
•
Our ratio of consolidated EBITDA to consolidated interest expense, as defined in the credit agreement, must be not less than 2.75 to 1.00 as of the last day of any fiscal quarter commencing March 31, 2008 unless we obtain an investment grade rating from Standard and Poor’s Ratings Services or Moody’s Investors Service and the rating from the other agencies is not less than Ba1 or BB+, as applicable. On November 10, 2007, Standard and Poor’s Rating Services raised our credit rating from BB+ to BBB-. On January 28, 2008, Moody’s upgraded the ratings of WPZ’s senior unsecured rating to Ba2 from Ba3.
Each of the above ratios is to be tested at the end of each fiscal quarter and measured on a rolling four-quarter basis commencing March 31, 2008. The credit agreement also includes customary events of default, upon which the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies.
On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility. As a result, we no longer have access to $75.0 million borrowing capacity under that facility.
On August 7, 2006 we amended and restated our $20.0 million revolving credit facility with Williams as the lender. The credit facility is available exclusively to fund working capital requirements. Borrowings under the credit facility mature on June 20, 2009 and bear interest at the one-month LIBOR. We pay a commitment fee to Williams on the unused portion of the credit facility of 0.30% annually. We are required to reduce all borrowings under the credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the credit facility. As of December 31, 2007, we have no outstanding borrowings under the working capital credit facility.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Leasing Activities
We lease the land on which a significant portion of Four Corners’ pipeline assets are located. The primary landowners are the Bureau of Land Management (BLM) and several Indian tribes. The BLM leases are for thirty years with renewal options. The most significant of the Indian tribal leases will expire at the end of 2022 and will then be subject to renegotiation. Four Corners leases compression units under a lease agreement with Exterran Holdings, Inc. The initial term of this agreement expired on June 30, 2006. We continue to lease these units on a month-to-month basis during the ongoing renegotiation. The month-to-month arrangement can be terminated by either party upon thirty days advance written notice. We also lease other minor office, warehouse equipment and automobiles under non-cancelable leases. The future minimum annual rentals under these non-cancelable leases as of December 31, 2007 are payable as follows:
Total rent expense was $21.2 million, $19.4 million and $18.9 million for 2007, 2006 and 2005, respectively.
Note 12.
Partners’ Capital
At December 31, 2007, of our total units outstanding, 75% were held by the public and the remaining units were held by affiliates of Williams.
Limited Partners’ Rights
Significant rights of the limited partners include the following:
•
Right to receive distributions of available cash within 45 days after the end of each quarter.
•
No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage our activities.
•
The general partner may be removed if such removal is approved by the unitholders holding at least 662/3% of the outstanding units voting as a single class, including units held by our general partner and its affiliates.
Subordinated Units
Our subordination period ended on February 19, 2008, the second business day following the distribution of our available cash when we met the requirements for early termination pursuant to our partnership agreement. As a result of the termination, the 7,000,000 outstanding subordinated units owned by four subsidiaries of Williams converted one-for-one to common units and will participate pro rata with the other common units in distributions of available cash beginning with the May 2008 distribution.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Class B Units
The Class B units were subordinated to common units and senior to subordinated units with respect to the payment of the minimum quarterly distribution, including any arrearages with respect to minimum quarterly distributions from prior periods, and with respect to the right to receive distributions upon our liquidation.
The Class B units had the same voting rights as our outstanding common units and were entitled to vote as a separate class on any matters that adversely affect the rights or preferences of the Class B units in relation to other classes of partnership interests or as required by law. The Class B units were not entitled to vote on the approval of the conversion of the Class B units into common units.
On May 21, 2007, the Class B units were converted into common units on a one-for-one basis upon approval of a majority of the common units eligible to vote.
Incentive Distribution Rights
Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:
In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
Note 13.
Long-Term Incentive Plan
In connection with our initial public offering, our general partner adopted the Williams Partners GP LLC Long-Term Incentive Plan (the Plan) for employees, consultants and directors of our general partner and its affiliates who perform services for us. The Plan permits the granting of awards covering an aggregate of 700,000 common units. These awards may be in the form of options, restricted units, phantom units or unit appreciation rights.
During 2007, 2006, and 2005 our general partner granted 2,403, 2,130 and 6,146 restricted units, respectively, pursuant to the Plan to members of our general partner’s board of directors who are not officers or employees of our general partner or its affiliates. These restricted units vested 180 days from the grant date. We recognized compensation expense of $77,000, $229,000 and $34,000 associated with these awards in 2007, 2006, and 2005, respectively.
Note 14.
Commitments and Contingencies
Commitments. Commitments for goods and services used in our operations and for construction and acquisition of property, plant and equipment are approximately $56.8 million at December 31, 2007.
Environmental Matters-Four Corners. Current federal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations required all unlined, earthen pits to be either permitted or closed by December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we have physically closed all of our pits
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
that were slated for closure under those regulations. We are presently awaiting agency approval of the closures for 40 to 50 of those pits.
We are also a participant in certain hydrocarbon removal and groundwater monitoring activities associated with certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at seven and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to eight years.
We have accrued liabilities totaling $0.7 million at December 31, 2007 and December 31, 2006 for these environmental activities. It is reasonably possible that we will incur costs in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities and other factors.
On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation to Four Corners that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. The NMED proposed a penalty of approximately $3 million. We are discussing the basis for and the scope of the proposed penalty with the NMED.
We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any material noncompliance under the various applicable environmental laws and regulations.
Environmental Matters-Conway. We are a participant in certain environmental remediation activities associated with soil and groundwater contamination at our Conway storage facilities. These activities relate to four projects that are in various remediation stages including assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE and are expected to be paid over the next two to nine years.
In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs for these projects to the extent such costs exceed a $4.2 million deductible, of which $3.1 million has been incurred to date from the onset of the policy. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25.0 million. We do not expect to submit any claims under this insurance policy prior to its expected expiration date on April 30, 2008. In addition, under an omnibus agreement with Williams entered into at the closing of our IPO, Williams agreed to indemnify us for the $4.2 million deductible not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14.0 million cap on the total amount of indemnity coverage under the omnibus agreement, which would be reduced by any actual recoveries under the environmental insurance policy. There is also a three-year time limitation on this indemnification from the August 23, 2005 IPO closing date. The benefit of this indemnification is accounted for as a capital contribution to us by Williams as the costs are reimbursed. At December 31, 2007 and December 31, 2006, we had accrued liabilities totaling $3.3 million and $5.9 million, respectively, for these environmental remediation activities. It is reasonably possible that we will incur losses in excess of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.
Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held on April 1, 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.
Grynberg. In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, including us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the Department of Justice announced that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against us. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including us, be dismissed. On October 20, 2006, the court dismissed all claims against us. In November 2006, Grynberg filed his notice of appeals with the Tenth Circuit Court of Appeals. The amount of any possible liability cannot be reasonably estimated at this time.
GE Litigation. General Electric International, Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant. We disagree with GEII on the quality of GEII’s work and the appropriate compensation. GEII asserts that it is entitled to additional extra work charges under the agreement, which we deny are due.
In 2006 we filed suit in federal court in Tulsa, Oklahoma against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc.; alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation; and sought unspecified damages. In 2007, the defendants and GEII filed counterclaims against us that alleged breach of contract and breach of the duty of good faith and fair dealing. Trial has been set for April 21, 2008. We are unable to quantify or estimate the possible liability.
Outstanding Registration Rights Agreement. On December 13, 2006, we issued approximately $350.0 million of common and Class B units in a private equity offering. In connection with these issuances, we entered into a registration rights agreement with the initial purchasers whereby we agreed to file a shelf registration statement providing for the resale of the common units purchased and the common units issued on conversion of the Class B units. We filed the shelf registration statement on January 12, 2007 and it became effective on March 13, 2007. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis. If the shelf is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or 105 days in any 365 day period, the purchasers are entitled to receive liquidated damages. Liquidated damages with respect to each purchaser are calculated as 0.25% of the Liquidated Damages Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an additional
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60 days, up to a maximum of 1% of the Liquidated Damages Multiplier per 30-day period; provided, the aggregate amount of liquidated damages payable to any purchaser is capped at 10% of the Liquidated Damages Multiplier. The Liquidated Damages Multiplier, with respect to each purchaser, is (i) the product of $36.59 times the number of common units purchased plus (ii) the product of $35.81 times the number of Class B units purchased. Due to amendments made to Rule 144 of the Securities Act in February 2008, related to securities acquired by non-affiliates from an issuer subject to public reporting requirements, we no longer have an obligation to keep our shelf registration statement effective and would have no liability for a failure to do so.
Other. We are not currently a party to any other legal proceedings but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.
Note 15.
Segment Disclosures
Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different industry knowledge, technology and marketing strategies. The accounting policies of the segments are the same as those described in Note 3, Summary of Significant Accounting Policies. Long-lived assets are comprised of property, plant and equipment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands, except per-unit amounts):
(a)
The fourth quarter of 2007 included
•
a $10.4 million impairment of the Carbonate Trend pipeline (see Note 7 Other (Income) Expense); and
•
a reduction in operating income from the shutdown of the Ignacio gas processing plant resulting from a fire.
(b)
Earnings per unit for the second quarter of 2007 has been recast to reflect the conversion of our outstanding Class B units into common units on a one-for-one basis, which occurred on May 21, 2007. This resulted in a $5.3 million non-cash allocation of income to the Class B units representing the Class B unit beneficial conversion feature during the second quarter of 2007. The $5.3 million beneficial conversion feature was computed as the product of the 6,805,492 Class B units and the difference between the fair value of a privately placed common unit on the date of issuance ($36.59) and the issue price of a privately placed Class B unit ($35.81). This resulted in an $0.08 decrease from $0.56 per unit to $0.48 per unit on our earnings per common unit for the second quarter of 2007. While this correction affects net income available to limited partners, it does not affect net income, cash flows nor does it affect total partners’ equity.
The following table presents the allocation of net income (loss) for purposes of calculating earnings per unit for each quarter in 2007, 2006 and 2005:
Item 9.
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d - 15(e) of the Securities Exchange Act) (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 general partner’s management, including our general partner’s chief executive officer and chief financial officer. Based upon that evaluation, our general partner’s chief executive officer and chief financial officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Our management, including our general partner’s chief executive officer and chief financial officer, does not expect that our 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 the 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.
Changes in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.
Management’s Report on Internal Control over Financial Reporting
See “Management’s Report on Internal Control over Financial Reporting” set forth above in Item 8, “Financial Statements and Supplementary Data.”
Item 9B.
Item 9B.
Other Information
There have been no events that occurred in the fourth quarter of 2007 that would need to be reported on Form 8-K that have not been previously reported.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
As a limited partnership, we have no directors or officers. Instead, our general partner, Williams Partners GP LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.
We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of an affiliate of our general partner.
All of the senior officers of our general partner are also senior officers of Williams and spend a sufficient amount of time overseeing the management, operations, corporate development and future acquisition initiatives of our business. Alan Armstrong, the chief operating officer of our general partner, is the principal executive responsible for the oversight of our affairs. Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.
The following table shows information for the directors and executive officers of our general partner as of February 25, 2008.
The directors of our general partner are elected for one-year terms and hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors of our general partner. There are no family relationships among any of the directors or executive officers of our general partner.
Steven J. Malcolm has served as the chairman of the board of directors and chief executive officer of our general partner since February 2005. Mr. Malcolm has served as president of Williams since September 2001, chief executive of Williams since January 2002 and chairman of the board of directors of Williams since May 2002. From May 2001 to September 2001, he served as executive vice president of Williams. From December 1998 to May 2001, he served as president and chief executive officer of Williams Energy Services, LLC. From November 1994 to December 1998, Mr. Malcolm served as the senior vice president and general manager of Williams Field Services Company. Mr. Malcolm has served as chairman of the board of directors and chief executive officer of the general partner of Williams Pipeline Partners L.P. since August 2007. Mr. Malcolm served as chief executive officer and chairman of the board of directors of the general partner of Williams Energy Partners L.P. (now known as Magellan Midstream Partners, L.P.) from its initial public offering in February 2001 to the sale of Williams’ interests therein in June 2003. Mr. Malcolm has served as a member of the board of directors of BOK Financial Corporation since 2002.
Donald R. Chappel has served as the chief financial officer and a director of our general partner since February 2005. Mr. Chappel has served as senior vice president and chief financial officer of Williams since April 2003. Mr. Chappel has served as chief financial officer and a director of the general partner of Williams Pipeline Partners L.P. since August 2007. Prior to joining Williams, Mr. Chappel, from 2000 to April 2003, founded and served as chief executive officer of a real estate leasing and development business in Chicago, Illinois. Mr. Chappel has more than 30 years of business and financial management experience with major corporations and partnerships. From 1987 though February 2000, Mr. Chappel served in various financial, administrative and operational leadership positions for Waste Management, Inc., including twice serving as chief financial officer, during 1997 and 1998 and most recently during 1999 through February 2000.
Alan S. Armstrong has served as the chief operating officer and a director of our general partner since February 2005. Since February 2002, Mr. Armstrong has served as a senior vice president of Williams
responsible for heading Williams’ midstream business unit. From 1999 to February 2002, Mr. Armstrong was vice president, gathering and processing in Williams’ midstream business unit and from 1998 to 1999 was vice president, commercial development, in Williams’ midstream business unit. From 1997 to 1998, Mr. Armstrong was vice president of retail energy in Williams’ energy services business unit. Prior to this, Mr. Armstrong served in various operations, engineering and commercial leadership roles within Williams.
James J. Bender has served as the general counsel of our general partner since February 2005. Mr. Bender has served as senior vice president and general counsel of Williams since December 2002. Mr. Bender has served as the general counsel of the general partner of Williams Pipeline Partners L.P. since August 2007. Prior to joining Williams in December 2002, Mr. Bender was senior vice president and general counsel with NRG Energy, Inc., a position held since June 2000. Mr. Bender was vice president, general counsel and secretary of NRG Energy from June 1997 to June 2000. NRG Energy filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003.
H. Michael Krimbill has served as a director of our general partner since August 2007. Mr. Krimbill has served as a director of Seminole Energy Services, LLC, a privately held natural gas marketing company, since November 2007. Mr. Krimbill was the president and chief financial officer of Energy Transfer Partners, L.P. from January 2004 until his resignation on January 10, 2007. Mr. Krimbill joined Heritage Propane Partners, L.P. (the predecessor of Energy Transfer Partners) as vice president and chief financial officer in 1990. Mr. Krimbill served as president of Heritage from 1999 to 2004 and as president and chief executive officer of Heritage from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners from 2000 to January 2007.
Bill Z. Parker has served as a director of our general partner since August 2005. Mr. Parker has served as a director of Laredo Petroleum L.L.C., a privately held independent oil and gas producing company, since May 2007. Mr. Parker served as a director for Latigo Petroleum, Inc., a privately held independent oil and gas production company, from January 2003 to May 2006, when it was acquired by POGO Producing Company. From April 2000 to November 2002, Mr. Parker served as executive vice president of Phillips Petroleum Company’s worldwide upstream operations. Mr. Parker was executive vice president of Phillips Petroleum Company’s worldwide downstream operations from September 1999 to April 2000.
Alice M. Peterson has served as a director of our general partner since September 2005. Ms. Peterson is the president of Syrus Global, a provider of ethics, compliance and reputation management solutions. Ms. Peterson has served as a director of Hanesbrands Inc., an apparel company, since August 2006. Ms. Peterson has served as a director for RIM Finance, LLC, a wholly owned subsidiary of Research In Motion, Ltd., the maker of the BlackBerrytm handheld device, since 2000. Ms. Peterson served as a director of TBC Corporation, a marketer of private branded replacement tires, from July 2005 to November 2005, when it was acquired by Sumitomo Corporation of America. From 1998 to August 2004, she served as a director of Fleming Companies. From December 2000 to December 2001, Ms. Peterson served as president and general manager of RIM Finance, LLC. From April 2000 to September 2000, Ms. Peterson served as the chief executive officer of Guidance Resources.com, a start-up business focused on providing online behavioral health and concierge services to employer groups and other associations. From 1998 to 2000, Ms. Peterson served as vice president of Sears Online and from 1993 to 1998, as vice president and treasurer of Sears, Roebuck and Co.
Rodney J. Sailor has served as a director of our general partner since October 2007. Mr. Sailor has served as vice president and treasurer of Williams since July 2005. He served as assistant treasurer of Williams from 2001 to 2005 and was responsible for capital structuring and capital markets transactions, management of Williams’ liquidity position and oversight of Williams’ balance sheet restructuring program. From 1985 to 2001, Mr. Sailor served in various other capacities for Williams. Mr. Sailor has served as a director of Apco Argentina Inc., a subsidiary of Williams engaged oil and gas exploration and production with interests in seven oil and gas concessions and two exploration permits in Argentina, since September 2006, and as a director and treasurer of the general partner of Williams Pipeline Partners L.P. since August 2007.
Governance
Our general partner adopted governance guidelines that address, among other areas, director independence standards, policies on meeting attendance and preparation, executive sessions of non-management directors and communications with non-management directors.
Director Independence
Because we are a limited partnership, the New York Stock Exchange does not require our general partner’s board of directors to be composed of a majority of directors who meet the criteria for independence required by the New York Stock Exchange or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors.
Our general partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with our general partner (either directly or indirectly or as a partner, shareholder or officer of an organization that has a relationship with our general partner). In order to make this determination, our general partner’s board of directors broadly considers all relevant facts and circumstances and applies categorical standards from our governance guidelines, which are set forth below and also available on our Internet website at http://www.williamslp.com under the “Investor Relations” caption. Under those categorical standards, a director will not be considered to be independent if:
•
the director, or an immediate family member of the director, has received during any twelve-month period within the last three years more than $100,000 per year in direct compensation from our general partner, us and any parent or subsidiary in a consolidated group with such entities (collectively, the Partnership Group), other than board and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service). Neither compensation received by a director for former service as an interim chairman or chief executive officer or other executive officer nor compensation received by an immediate family member for service as an employee of the Partnership Group will be considered in determining independence under this standard.
•
the director is a current employee, or has an immediate family member who is a current executive officer, of another company that has made payments to, or received payments from, the Partnership Group for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1.0 million, or 2% of the other company’s consolidated gross annual revenues. Contributions to tax exempt organizations are not considered “payments” for purposes of this standard.
•
the director is, or has been within the last three years, an employee of the Partnership Group, or an immediate family member is, or has been within the last three years, an executive officer, of the Partnership Group. Employment as an interim chairman or chief executive officer or other executive officer will not disqualify a director from being considered independent following that employment.
•
(i) the director or an immediate family member is a current partner of a present or former internal or external auditor for the Partnership Group, (ii) the director is a current employee of such a firm, (iii) the director has an immediate family member who is a current employee of such a firm and participates in such firm’s audit, assurance or tax compliance (but not tax planning) practice or (iv) the director or an immediately family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on an audit for the Partnership Group within that time.
•
if the director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the Partnership Group’s present executive officers at the same time serves or served on that company’s compensation committee.
•
if the board of directors determines that a discretionary contribution made by any member of the Partnership Group to a non-profit organization with which a director, or a director’s spouse, has a relationship, impacts the director’s independence.
Our general partner’s board of directors has affirmatively determined that each of Ms. Peterson and Messrs. Krimbill and Parker is an “independent director” under the current listing standards of the New York Stock Exchange and our categorical director independence standards. In addition, our general partner’s board of directors affirmatively determined that Mr. Thomas C. Knudson, who retired from the board of directors in August 2007, was an “independent director” under such standards. In so doing, the board of directors determined that each of these individuals met the “bright line” independence standards of the New York Stock Exchange. In addition, the board of directors considered relationships with our general partner, either directly or indirectly. The purpose of this review was to determine whether any such relationships or transactions were inconsistent with a determination that the director is independent. The board of directors considered the fact that Mr. Knudson serves as a director for NATCO Group Inc., which provided goods or services for certain of our subsidiaries, affiliates of Williams and Discovery. The board of directors also considered the fact that Mr. Krimbill serves as a director of Seminole Energy Services LLC, which is a customer and vendor to certain subsidiaries of Williams. The board of directors also considered the fact that Ms. Peterson is a director of an affiliate of Research in Motion Corp., which provides goods or services to affiliates of Williams. The board of directors noted that, since Ms. Peterson and Messrs. Knudson and Krimbill do not serve as executive officers and do not own a significant amount of voting securities of any of these entities, these relationships are not material. Accordingly, the board of directors of our general partner affirmatively determined that all of the directors mentioned above are independent. Because Messrs. Armstrong, Chappel, Malcolm, Sailor and Phillip D. Wright (who served as a director of our general partner until October 2007) are employees, officers and/or directors of Williams, they are not independent under these standards.
Ms. Peterson and Messrs. Krimbill and Parker do not serve as an executive officer of any non-profit organization to which the Partnership Group made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2% of such organization’s consolidated gross revenues. Further, in accordance with our categorical director independence standards, there were no discretionary contributions made by any member of the Partnership Group to a non-profit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.
In addition, our general partner’s board of directors determined that each of Ms. Peterson and Messrs. Krimbill and Parker, who constitute the members of the audit committee of the board of directors, meet the heightened independence requirements of the New York Stock Exchange for audit committee members.
Meeting Attendance and Preparation
Members of the board of directors of our general partner are expected to attend at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing written materials distributed in advance.
Executive Sessions of Non-Management Directors
Our general partner’s non-management board members periodically meet outside the presence of our general partner’s executive officers. The chairman of the audit committee serves as the presiding director for executive sessions of non-management board members. The current chairman of the audit committee and the presiding director is Ms. Alice M. Peterson.
Communications with Directors
Interested parties wishing to communicate with our general partner’s non-management directors, individually or as a group, may do so by contacting our general partner’s corporate secretary or the presiding director. The contact information is maintained on the investor relations/corporate governance page of our website at http://www.williamslp.com.
The current contact information is as follows:
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Corporate Secretary
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Presiding Director
E-mail: brian.shore@williams.com
Board Committees
The board of directors of our general partner has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 and a conflicts committee. The following is a description of each of the committees and committee membership as of February 25, 2008.
Board Committee Membership
ü
= committee member
•
= chairperson
Audit Committee
Our general partner’s board of directors has determined that all members of the audit committee meet the heightened independence requirements of the New York Stock Exchange for audit committee members and that all members are financially literate as defined by the rules of the New York Stock Exchange. The board of directors has further determined that Ms. Alice M. Peterson and Mr. H. Michael Krimbill qualify as audit committee “financial experts” as defined by the rules of the SEC. Biographical information for Ms. Peterson and Mr. Krimbill is set forth above. The audit committee is governed by a written charter adopted by the board of directors. For further information about the audit committee, please read the “Report of the Audit Committee” below and “Principal Accountant Fees and Services.”
Conflicts Committee
The conflicts committee of our general partner’s board of directors reviews specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if resolution of the conflict is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience requirements established by the New York Stock Exchange and the Sarbanes-Oxley Act of 2002 and other federal securities laws. Any matters approved by the conflicts committee will be conclusively deemed fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe to us or our unitholders.
Code of Business Conduct and Ethics
Our general partner has adopted a code of business conduct and ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the code of business conduct and ethics on behalf of our general partner’s chief executive officer, chief financial officer, controller and persons performing similar functions on our Internet website at http://www.williamslp.com under the “Investor Relations” caption, promptly following the date of any such amendment or waiver.
Internet Access to Governance Documents
Our general partner’s code of business conduct and ethics, governance guidelines and the charter for the audit committee are available on our Internet website at http://www.williamslp.com under the “Investor Relations” caption. We will provide, free of charge, a copy of our code of business conduct and ethics or any of our other governance documents listed above upon written request to our general partner’s corporate secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s officers and directors and persons who own more than 10% of a registered class of our equity securities to file with the SEC and the New York Stock Exchange reports of ownership of our securities and changes in reported ownership. Officers and directors of our general partner and greater than 10% common unitholders are required to by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2007 our general partner’s officers, directors and greater than 10% common unitholders filed all reports they were required to file under Section 16(a).
Transfer Agent and Registrar
Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units. Contact information for Computershare is as follows:
Computershare Trust Company, N.A.
P.O. Box 43069
Providence, Rhode Island 02940-3069
Phone: (781) 575-2879 or toll-free, (877) 498-8861
Hearing impaired: (800) 952-9245
Internet: www.computershare.com/investor
Send overnight mail to:
Computershare
250 Royall St.
Canton, Massachusetts 02021
CEO/CFO Certifications
We submitted the certification of Steven J. Malcolm, our general partner’s chairman of the board and chief executive officer, to the New York Stock Exchange pursuant to NYSE Section 303A.12(a) on March 26, 2007. In addition, the certificates of our chief executive officer and chief financial officer as required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2 to this annual report.
REPORT OF THE AUDIT COMMITTEE
The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The audit committee operates under a written charter approved by the board. The charter, among other things, provides that the audit committee has authority to appoint, retain and oversee the independent auditor. In this context, the audit committee:
•
reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;
•
reviewed with Ernst & Young LLP, the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of Williams Partners L.P.’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards;
•
received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Ernst & Young LLP;
•
discussed with Ernst & Young LLP its independence from management and Williams Partners L.P. and considered the compatibility of the provision of nonaudit services by the independent auditors with the auditors’ independence;
•
discussed with Ernst & Young LLP the matters required to be discussed by statement on auditing standards No. 61, as amended (communications with audit committees);
•
discussed with Williams Partners L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of Williams Partners L.P.’s internal controls and the overall quality of Williams Partners L.P.’s financial reporting;
•
based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2007, for filing with the SEC; and
•
approved the selection and appointment of Ernst & Young LLP to serve as Williams Partners L.P.’s independent auditors.
This report has been furnished by the members of the audit committee of the board of directors:
- Alice M. Peterson - chairman
- Bill Z. Parker
- H. Michael Krimbill
February 18, 2008
The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by Williams Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.
Item 11.
Item 11.
Executive Compensation
Compensation Discussion and Analysis
We and our general partner, Williams Partners GP LLC, were formed in February 2005. We are managed by the executive officers of our general partner who are also executive officers of Williams. Neither we nor our general partner have a compensation committee. The executive officers of our general partner are compensated directly by Williams. All decisions as to the compensation of the executive officers of our general partner who are involved in our management are made by the compensation committee of Williams. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner and we make no decisions relating to such compensation. None of the executive officers of our general partner have employment agreements or are otherwise specifically compensated for their service as an executive officer of our general partner. A full discussion of the policies and programs of the compensation committee of Williams will be set forth in the proxy statement for Williams’ 2008 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors - SEC Filings.” We reimburse our general partner for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for more information regarding this arrangement.
Executive Compensation
Information regarding the portion of Mr. Armstrong’s, Mr. Bender’s, Mr. Chappel’s and Mr. Malcolm’s compensation and employment-related expenses allocable to us may be found in this filing under the heading “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner.”
Further information regarding the compensation of our principal executive officer, Steven J. Malcolm, who also serves as the chairman, president and chief executive officer of Williams, and our principal financial officer, Donald R. Chappel, who also serves as the chief financial officer of Williams, will be set forth in the proxy statement for Williams’ 2008 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http:/www.williams.com under the heading “Investors - SEC Filings.”
Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. Steven J. Malcolm, our general partner’s chief executive officer and chairman of the board of directors serves as the chairman of the board and chief executive officer of Williams. Alan S. Armstrong and Donald R. Chappel, who are directors of our general partner, are also executive officers of Williams. Rodney J. Sailor, who is a director of our general partner, is also a non-executive officer and an employee of Williams. In addition, Phillip D. Wright, who resigned as a director of our general partner on October 23, 2007, is also an executive officer of Williams. However, all compensation decisions with respect to each of these persons are made by Williams and none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.
Board Report on Compensation
Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.
The Board of Directors of Williams Partners GP LLC:
Alan S. Armstrong, Donald R. Chappel,
H. Michael Krimbill, Steven J. Malcolm
Bill Z. Parker, Alice M. Peterson,
Rodney J. Sailor
Compensation of Directors
We are managed by the board of directors of our general partner. Members of the board of directors who are also officers or employees of Williams or an affiliate of us or Williams do not receive additional compensation for serving on the board of directors. Please read “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner” for information about how we reimburse our general partner for direct and indirect general and administrative expenses attributable to our management. Non-employee directors each receive an annual compensation package consisting of the following: (a) $50,000 cash retainer; (b) restricted units representing our limited partnership interests valued at $25,000 in the aggregate; and (c) $5,000 cash for service on the conflicts or audit committees of the board of directors. The annual compensation package is paid to each non-employee director based on their service on the board of directors for the period beginning on August 22 of each fiscal year and ending on August 21 of each fiscal year. If a non-employee director’s service on the board of directors commences on or after December 1 of a fiscal year, such non-employee director will receive a prorated annual compensation package for such fiscal year. In addition to the annual compensation package, each non-employee director receives a one-time grant of restricted units valued at $25,000 on the date of first election to the board of directors. Restricted units awarded to non-employee directors under the annual compensation package or upon first election to the board of directors are granted under the Williams Partners GP LLC Long-Term Incentive Plan and vest 180 days after the date of grant. Cash distributions are paid on these restricted units. Each non-employee director is also reimbursed for out-of -pocket expenses in connection with attending meetings of the board of directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse non-employee directors for the costs of education programs relevant to their duties as board members.
For their service, non-management directors received the following compensation in 2007:
Director Compensation Fiscal Year 2007
(1)
Awards were granted under the Williams Partners GP LLC Long-Term Incentive Plan. Awards are in the form of restricted units and are shown using a dollar value equal to the 2007 compensation expense computed in accordance with Statement of Financial Accounting Standards No. 123(R). Cash distributions are paid on these restricted units at the same time and same rate as distributions paid to our unitholders.
(2)
The grant date fair value for the 2007 restricted units for Mr. Krimbill is $50,010. At fiscal year end, Mr. Krimbill had an aggregate of 1,243 restricted units outstanding.
(3)
Mr. Knudson did not receive any restricted units in 2007. At fiscal year end, Mr. Knudson did not have any restricted units outstanding. Mr. Knudson retired from the board of directors of our general partner on August 22, 2007.
(4)
The grant date fair value for the 2007 restricted units for Mr. Parker is $25,015. At fiscal year end, Mr. Parker had an aggregate of 580 restricted units outstanding.
(5)
The grant date fair value for the 2007 restricted units for Ms. Peterson is $25,015. At fiscal year end, Ms. Peterson had an aggregate of 580 restricted units outstanding.
Long-Term Incentive Plan
In connection with our IPO, our general partner adopted the Williams Partners GP LLC Long-Term Incentive Plan for employees, consultants and directors of our general partner and employees and consultants of its affiliates who perform services for our general partner or its affiliates. To date, the only grants under the plan have been grants of restricted units to directors who are not officers or employees of us or our affiliates. On November 28, 2006, the board of directors of our general partner dissolved its compensation committee. The only function performed by the committee prior to its dissolution was to administer the Williams Partners GP LLC Long-Term Incentive Plan. Accordingly, also on November 28, 2006, the board of directors approved an amendment to the long-term incentive plan to allow the full board of directors to administer the plan. The long-term incentive plan consists of four components: restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan currently permits the grant of awards covering an aggregate of 700,000 units.
Our general partner’s board of directors, in its discretion may terminate, suspend or discontinue the long-term incentive plan at any time with respect to any award that has not yet been granted. Our general partner’s board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.
Restricted Units and Phantom Units
A restricted unit is a common unit subject to forfeiture prior to the vesting of the award. A phantom unit will be a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. The board of directors of our general partner may determine to make grants under the plan of restricted units and phantom units to employees, consultants and directors containing such terms as the board of directors shall determine. The board of directors determines the period over which restricted units and phantom units granted to employees, consultants and directors will vest. The board of directors may base its determination upon the achievement of specified financial objectives. In addition, the restricted units and phantom units will vest upon a change of control of Williams Partners L.P., our general partner or Williams, unless provided otherwise by the board of directors.
If a grantee’s employment, service relationship or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the board of directors provides otherwise. Common units to be delivered in connection with the grant of restricted units or upon the vesting of phantom units may be common units acquired by our general partner on the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner is entitled to reimbursement by us for the cost incurred in acquiring common units. Thus, the cost of the restricted units and delivery of common units upon the vesting of phantom units will be borne by us. If we issue new common units in connection with the grant of restricted units or upon vesting of the phantom units, the total number of common units outstanding will increase. The board of directors of our general partner, in
its discretion, may grant tandem distribution rights with respect to restricted units and tandem distribution equivalent rights with respect to phantom units.
Unit Options and Unit Appreciation Rights
The long-term incentive plan permits the grant of options covering common units and the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in common units, cash or a combination thereof, as determined by the board of directors in its discretion. Our general partner’s board of directors may make grants of unit options and unit appreciation rights under the plan to employees, consultants and directors containing such terms as the board of directors shall determine. Unit options and unit appreciation rights may not have an exercise price that is less than the fair market value of the common units on the date of grant. In general, unit options and unit appreciation rights granted will become exercisable over a period determined by the board of directors. In addition, the unit options and unit appreciation rights will become exercisable upon a change in control of Williams Partners L.P., our general partner or Williams, unless provided otherwise by the board of directors. The board of directors, in its discretion may grant tandem distribution equivalent rights with respect to unit options and unit appreciation rights.
Upon exercise of a unit option (or a unit appreciation right settled in common units), our general partner will acquire common units on the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received from a participant at the time of exercise. Thus, the cost of the unit options (or a unit appreciation right settled in common units) will be borne by us. If we issue new common units upon exercise of the unit options (or a unit appreciation right settled in common units), the total number of common units outstanding will increase, and our general partner will pay us the proceeds it receives from an optionee upon exercise of a unit option. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of common units of Williams Partners L.P. that are owned by:
•
each person known by us to be a beneficial owner of more than 5% of the units;
•
each of the directors of our general partner;
•
each of the named executive officers of our general partner; and
•
all directors and executive officers of our general partner as a group.
The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.
Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.
Percentage of total units beneficially owned is based on 52,774,728 units outstanding. Unless otherwise noted below, the address for the beneficial owners listed below is One Williams Center, Tulsa, Oklahoma 74172-0172.
*
Less than 1%.
(a)
As noted in the Schedule 13D/A filed with the SEC on January 18, 2008, The Williams Companies, Inc. is the ultimate parent company of Williams Energy Services, LLC, Williams Partners GP LLC, Williams Energy, L.L.C., Williams Discovery Pipeline LLC and Williams Partners Holdings LLC and may, therefore, be deemed to beneficially own the units held by each of these companies. The Williams Companies, Inc.’s common stock is listed on the New York Stock Exchange under the symbol “WMB.” The Williams Companies, Inc. files information with or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Securities Exchange Act of 1934 (the Act). Williams Discovery Pipeline LLC is the record holder of 1,425,466 common units. Williams Energy Services, LLC is the record owner of 1,045,923 common units and, as the sole stockholder of MAPCO Inc. and the sole member of Williams Discovery Pipeline LLC and Williams Partners GP LLC, may, pursuant to Rule 13d-3, be deemed to beneficially own the units beneficially owned by MAPCO Inc., Williams Discovery Pipeline LLC and Williams Partners GP LLC. MAPCO Inc., as the sole member of Williams Energy, L.L.C., may, pursuant to Rule 13d-3, be deemed to beneficially own the units held by Williams Energy, L.L.C.
(b)
Based solely on the Schedule 13G filed with the SEC on February 19, 2008, Lehman Brothers Holdings Inc. (Holdings), may be deemed the beneficial owner of 409,700 common units directly owned by Lehman Brothers Inc. (LBI), a broker-dealer registered under Section 15 of the Act, 2,389,206 common units (including 2,200,000 common units issuable upon the exercise of call options) owned by Lehman Brothers MLP Opportunity Fund LP (MLP Opport. Fund) and 622,400 common units owned by Lehman Brothers MLP Partners, LP (MLP Partners). The Schedule 13G notes that: (i) LBI is a wholly owned subsidiary of Holdings; (ii) Lehman Brothers MLP Opportunity Associates LP (MLP Opport. Assoc LP) is the general partner of MLP Opport. Fund, Lehman Brothers MLP Opportunity Associates LLC (MLP Opport. Assoc LLC) is the general partner of MLP Opport. Assoc LP and MLP Opport. Assoc LLC is wholly owned by
Holdings; and (iii) Lehman Brothers MLP Associates, L.P. (MLP Assoc LP) is the general partner of MLP Partners, LBI Group Lnc. (LBI Group) is the general partner of MLP Assoc LP and LBI Group is wholly owned by Holdings. The address of Holdings is 745 Seventh Avenue, New York, New York 10019.
(c)
Based solely on the Schedule 13G/A filed with the SEC on February 6, 2008, Prudential Financial, Inc. (Prudential), a Parent Holding Company as defined in the Act, may be deemed to be the beneficial owner of securities beneficially owned by the Registered Investment Advisors and Broker Dealers listed in such Schedule 13G/A, of which Prudential is the direct or indirect parent, and may have direct or indirect voting power over the reported common units which are held for Prudential’s benefit or for the benefit of its clients by its separate accounts, externally managed accounts, registered investment companies, subsidiaries and/or affiliates. The 13G/A indicates that Prudential has sole voting and dispositive power over 1,115 common units and shared voting and dispositive power over 3,023,749 common units. The Schedule 13G notes that Prudential reported the combined holdings of these entities for the purpose of administrative convenience. The address of Prudential is 751 Broad Street, Newark, New Jersey 07102-3777.
(d)
Based solely on the Schedule 13G filed with the SEC on June 11, 2007, Jennison Associates LLC (Jennison), an Investment Advisor as defined in the Act, may be deemed to be the beneficial owner of securities beneficially owned by investment companies, insurance separate accounts and institutional clients for which it acts as an investment advisor. The Schedule 13G notes that Prudential is a managed portfolio that indirectly owns 100% of equity interests of Jennison, and may have direct or indirect voting power and/or dispositive power over the common units which Jennison may be deemed to beneficially own. The Schedule 13G further notes that Jennison does not file jointly with Prudential and the common units reported by Jennison in its Schedule 13G may be included in the common units reported in the Schedule 13G filed by Prudential. The address of Jennison is 466 Lexington Avenue, New York, New York 10017.
(e)
Mr. Armstrong is the trustee of The Shelly Stone Armstrong Trust dated August 10, 2004, and has the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of, 5,000 common units that are held by the trust.
(f)
Includes 663 unvested restricted units granted pursuant to the Williams Partners GP LLC Long-Term Incentive Plan.
(g)
Represents units beneficially owned by Mr. Malcolm that are held by the Steven J. Malcolm Revocable Trust.
The following table sets forth, as of February 22, 2008, the number of shares of common stock of Williams owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
*
Less than 1%.
(a)
Includes shares held under the terms of incentive and investment plans as follows: Mr. Armstrong, 14 shares in The Williams Companies Investment Plus Plan and 128,414 restricted stock units; Mr. Bender, 2,800 shares owned by children, 122,693 restricted stock units and 28,490 beneficially owned shares; Mr. Chappel, 186,642 restricted stock units and 71,643 beneficially owned shares; Mr. Malcolm, 45,736 shares in The Williams Companies Investment Plus Plan, 468,092 restricted stock units and 405,384 beneficially owned shares; and Mr. Sailor, 10,120 shares in The Williams Investment Plus Plan, 22,933 restricted stock units and 654 beneficially owned shares. Restricted stock units do not provide the holder with voting or investment power.
(b)
The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 22, 2008. Shares subject to options cannot be voted.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information concerning common units that were potentially subject to issuance under the Williams Partners GP LLC Long-Term Incentive Plan as of December 31, 2007. For more information about this plan, which did not require approval by our limited partners, please read Note 13, Long-Term Incentive Plan, of our Notes to Consolidated Financial Statements and “Executive Compensation - Long-Term Incentive Plan.”
(1)
2,403 unvested restricted units granted pursuant to the Williams Partners GP LLC Long-Term Incentive Plan were outstanding as of December 31, 2007. 1,740 restricted units vested on February 18, 2007 and 663 vest on June 12, 2008. No value is shown in column (b) of the table because the restricted units do not have an exercise price. To date, the only grants under the plan have been grants of restricted units.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Transactions with Related Persons
After the conversion of our subordinated units on February 19, 2008, our general partner and its affiliates own 11,613,527 common units representing a 21.6% limited partner interest in us. Williams also indirectly owns 100% of our general partner, which allows it to control us. Certain officers and directors of our general partner also serve as officers and/or directors of Williams. In addition, our general partner owns a 2% general partner interest and incentive distribution rights in us.
In addition to the related transactions and relationships discussed below, information about such transactions and relationships is included in Note 5, Related Party Transactions, of our Notes to Consolidated Financial Statements and is incorporated herein by reference in its entirety.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates, which include Williams, in connection with the ongoing operation and liquidation of
Williams Partners L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Operational Stage
Distributions of available cash to our general partner and its affiliates
We will generally make cash distributions 98% to unitholders, including our general partner and its affiliates as holders of an aggregate of 11,613,527 common units and the remaining 2% to our general partner.
In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” For further information about distributions, please read “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
Reimbursement of expenses to our general partner and its affiliates
Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses.
Withdrawal or removal of our general partner
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.
Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other compensation for its management of our business. However, we reimburse our general partner for expenses incurred on our behalf, including expenses incurred in compensating employees of an affiliate of our general partner who perform services on our behalf. These expenses include all allocable expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no minimum or maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our behalf, except that pursuant to the omnibus agreement, Williams will provide a partial credit for general and administrative expenses that we incur for a period of five years following our IPO of common units in August 2005. Please read “- Omnibus Agreement” below for more information.
For the fiscal year ended December 31, 2007, our general partner allocated $251,182 of salary and non-equity incentive plan compensation expense to us for Steven J. Malcolm, the chairman of the board and chief executive officer of our general partner, $109,940 of salary and non-equity incentive plan compensation expense to us for Donald R. Chappel, the chief financial officer of our general partner, $312,047 of salary and non-equity incentive plan compensation expense to us for Alan S. Armstrong, the chief operating officer of our general partner, $73,883 of salary and non-equity incentive plan compensation expense to us for James J. Bender, the general counsel of our general partner and $31,248 of salary and non-equity incentive
plan compensation expense to us for Rodney J. Sailor, a director of our general partner who is also a non-executive officer and employee of Williams. Our general partner also allocated to us $789,029 for Mr. Malcolm, $245,670 for Mr. Chappel, $593,603 for Mr. Armstrong, $135,483 for Mr. Bender and $35,843 for Mr. Sailor, which expenses are attributable to additional compensation paid to each of them and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams 401(k) plan and premiums for life insurance. Our general partner also allocated to us a portion of Williams’ expenses related to perquisites for each of Messrs. Malcolm, Chappel, Bender, Sailor and Armstrong, which allocation did not exceed $10,000 for any of these persons. The foregoing amounts exclude expenses allocated by Williams to Discovery and Wamsutter. No awards were granted to our general partner’s executive officers under the Williams Partners GP LLC Long-Term Incentive Plan in 2006 or 2007. The total compensation received by Mr. Malcolm, the chairman of the board and chief executive officer of our general partner who is also the chairman, president and chief executive officer of Williams, and Mr. Chappel, the chief financial officer of our general partner who is also the chief financial officer of Williams, will be set forth in the proxy statement for Williams’ 2008 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors - SEC Filings.”
For the year ended December 31, 2007, we incurred approximately $103.7 million in total operating and maintenance and general and administrative expenses from Williams incurred on our behalf pursuant to the partnership agreement.
Omnibus Agreement
Upon the closing of our initial public offering, we entered into an omnibus agreement with Williams and its affiliates that was not the result of arm’s-length negotiations. The omnibus agreement governs our relationship with Williams regarding the following matters:
•
reimbursement of certain general and administrative expenses;
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indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;
•
reimbursement for certain expenditures; and
•
a license for the use of certain software and intellectual property.
General and Administrative Expenses
Williams will provide us with a five-year partial credit for general and administrative (G&A) expenses incurred on our behalf. For 2005, the amount of this credit was $3.9 million on an annualized basis but was pro rated from the closing of our initial public offering in August 2005 through the end of the year, resulting in a $1.4 million credit. In 2006 and 2007, the amounts of the G&A credit were $3.2 million and $2.4 million, respectively, and in 2008 the amount of the credit will be $1.6 million. We will receive $800,000 in 2009 and after 2009, we will no longer receive any credit and will be required to reimburse Williams for all of the general and administrative expenses incurred on our behalf.
Indemnification for Environmental and Related Liabilities
Williams agreed to indemnify us after the closing of our initial public offering against certain environmental and related liabilities arising out of or associated with the operation of the assets before the closing date of our initial public offering. These liabilities include both known and unknown environmental and related liabilities, including:
•
remediation costs associated with the KDHE Consent Orders and certain NGLs associated with our Conway storage facilities;
•
the costs associated with the installation of wellhead control equipment and well meters at our Conway storage facility;
•
KDHE-related cavern compliance at our Conway storage facility; and
•
the costs relating to the restoration of the overburden along our Carbonate Trend pipeline in connection with erosion caused by Hurricane Ivan in September 2004.
Williams will not be required to indemnify us for any project management or monitoring costs. This indemnification obligation will terminate three years after the closing of our initial public offering, except in the case of the remediation costs associated with the KDHE Consent Orders which will survive for an unlimited period of time. There is an aggregate cap of $14.0 million on the amount of indemnity coverage, including any amounts recoverable under our insurance policy covering those remediation costs and unknown claims at Conway. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental.” In addition, we are not entitled to indemnification until the aggregate amounts of claims exceed $250,000. Liabilities resulting from a change of law after the closing of our initial public offering are excluded from the environmental indemnity by Williams for the unknown environmental liabilities.
Williams will also indemnify us for liabilities related to:
•
certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to us in connection with our initial public offering are located and failure to obtain certain consents and permits necessary to conduct our business that arise within three years after the closing of our initial public offering; and
•
certain income tax liabilities attributable to the operation of the assets contributed to us in connection with our initial public offering prior to the time they were contributed.
For the year ended December 31, 2007, Williams indemnified us $2.9 million, primarily for KDHE related compliance. Including 2007, Williams has indemnified us for an aggregate of $5.4 million pursuant to the omnibus agreement.
Reimbursement for Certain Expenditures Attributable to Discovery
Williams has agreed to reimburse us for certain capital expenditures, subject to limits, including for certain “excess” capital expenditures in connection with Discovery’s Tahiti pipeline lateral expansion project. The initial expected cost of the Tahiti pipeline lateral expansion project was approximately $69.5 million, of which our 40% share, included in the initial public offering and reimbursed under the omnibus agreement, is approximately $27.8 million. Williams will reimburse us for the excess (up to $3.4 million) of the total cost of the Tahiti pipeline lateral expansion project above the amount of the required escrow deposit ($24.4 million) attributable to our 40% interest in Discovery, included in the initial public offering and reimbursed under the omnibus agreement. The current expected cost of the Tahiti pipeline lateral expansion project is $73.2 million. Williams will reimburse us for these capital expenditures upon the earlier to occur of a capital call from Discovery or Discovery actually incurring the expenditure. Williams has indemnified us for an aggregate of $1.6 million for Discovery’s capital call related to this project.
Intellectual Property License
Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.
Amendments
The omnibus agreement may not be amended without the prior approval of the conflicts committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of our common units.
Competition
Williams is not restricted under the omnibus agreement from competing with us. Williams may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
Credit Facilities
Working Capital Facility
At the closing of our initial public offering in August 2005, we entered into a $20.0 million revolving credit facility with Williams as the lender. The facility was amended and restated on August 7, 2006. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility will mature on June 20, 2009 and bear interest at the same rate as would be available for borrowings under the Williams credit agreement described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition and Liquidity - Credit Facilities.”
We are required to reduce all borrowings under our working capital credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility.
Williams Credit Agreement
On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility. As a result, we no longer have access to a $75.0 million borrowing capacity under that facility.
Wamsutter Credit Facility
Prior to our acquisition of the Wamsutter Ownership Interests, Wamsutter entered into a $20.0 million revolving credit facility with Williams as the lender. The facility is available to fund working capital borrowings and for other purposes. Borrowings under the facility will mature on December 9, 2008. Wamsutter will pay a commitment fee to Williams on the unused portion of the credit facility of 0.175% annually. Interest on any borrowings under the facility will be calculated based upon the one-month LIBOR rate determined the date of the borrowing.
Wamsutter Limited Liability Company Agreement
We and an affiliate of Williams have entered into an amended and restated limited liability company agreement for Wamsutter. This agreement governs the ownership and management of Wamsutter and provides for quarterly distributions of available cash to the members. Please read “Business and Properties - Narrative Description of Business - Gathering and Processing - West - Wamsutter LLC Agreement.”
Additionally, the Wamsutter LLC agreement appoints Williams as the operator. As such, effective December 1, 2007 Williams is reimbursed on a monthly basis for all direct and indirect expenses it incurs on behalf of Wamsutter including Wamsutter’s allocable share of general and administrative costs.
Wamsutter participates in Williams’ cash management program. Therefore, Wamsutter carries no cash balances. Pursuant to this agreement, Wamsutter has made net advances to Williams, which have been classified as a component of owner’s equity because, although the advances are due on demand, Williams has not historically required repayment or repaid amounts owed to Wamsutter.
Discovery Operating and Maintenance Agreements
Discovery is party to three operating and maintenance agreements with Williams: one relating to Discovery Producer Services LLC, one relating to Discovery Gas Transmission LLC and another relating to the Paradis Fractionation Facility and the Larose Gas Processing Plant. Under these agreements, Discovery is required to reimburse Williams for direct payroll and employee benefit costs incurred on Discovery’s behalf. Most costs for materials, services and other charges are third-party charges and are invoiced directly to Discovery. Discovery is required to pay Williams a monthly operation and management fee to cover the cost
of accounting services, computer systems and management services provided to Discovery under each of these agreements. Discovery also pays Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis.
For the year ended December 31, 2007, Discovery reimbursed Williams $4.8 million for direct payroll and employee benefit costs, as well as $0.4 million for capitalized labor costs, pursuant to the operating and maintenance agreements and paid Williams $0.7 million for operation and management fees, as well as a $0.2 million fee for managing capitalized projects, pursuant to the operating and maintenance agreements.
Wamsutter Purchase and Sale Agreement
On November 30, 2007, we entered into a Purchase and Sale Agreement with Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, our general partner and Williams Partners Operating LLC (Williams OLLC). Pursuant to the Purchase and Sale Agreement, on December 11, 2007, we acquired ownership interests in Wamsutter consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 50% of the initial Class C units (or 20 Class C units) representing limited liability company membership interests in Wamsutter for aggregated consideration of $750.0 million. The conflicts committee of the board of directors of our general partner recommended approval of the acquisition of the membership interests in Wamsutter. The committee retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration paid by us to Williams was fair, from a financial point of view, to us and our public unitholders. In connection with the transactions contemplated by the Purchase and Sale Agreement, we contributed the membership interests in Wamsutter to our wholly owned subsidiary, Williams Partners Operating LLC, on December 11, 2007.
Discovery Purchase and Sale Agreement
On June 20, 2007, Williams Partners Operating LLC, our operating subsidiary, entered into a Purchase and Sale Agreement with Williams Energy, L.L.C. and Williams Energy Services, LLC, pursuant to which the Williams subsidiaries agreed to sell a 20% limited liability company interest in Discovery to Williams OLLC for aggregate consideration of $78.0 million. Upon closing Williams OLLC became the owner of a 60% interest in Discovery, as Williams OLLC already owned a 40% interest in Discovery, which it acquired as part of the formation transaction consummated concurrently with our IPO on August 23, 2005. The remaining 40% interest in Discovery is owned by DCP Assets Holding, LP. The conflicts committee of the board of directors of our general partner recommended approval of the acquisition of the additional 20% interest in Discovery. The committee retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration paid by us to Williams was fair, from a financial point of view, to us and our public unitholders.
Natural Gas and NGL Purchasing Contracts
Certain subsidiaries of Williams market substantially all of the NGLs and excess natural gas to which Wamsutter and Discovery, our Conway fractionation and storage facility and our Four Corners system take title. Wamsutter and Discovery, our Conway fractionation and storage facility and our Four Corners system conduct the sales of the NGLs and excess natural gas to which they take title pursuant to base contracts for sale and purchase of natural gas and a natural gas liquids master purchase, sale and exchange agreement. These agreements contain the general terms and conditions governing the transactions such as apportionment of taxes, timing and manner of payment, choice of law and confidentiality. Historically, the sales of natural gas and NGLs to which Wamsutter and Discovery, our Conway fractionation and storage facility and our Four Corners system take title have been conducted at market prices with certain subsidiaries of Williams as the counter parties. Additionally, Wamsutter and Discovery, our Conway fractionation and storage facility and our Four Corners system may purchase natural gas to meet their fuel and other requirements and our Conway storage facility may purchase NGLs as needed to maintain inventory balances.
For the year ended December 31, 2007, we sold $268.0 million of products to a subsidiary of Williams that purchases substantially all of the NGLs and excess natural gas to which our Conway fractionation and storage facility and our Four Corners system take title based on market pricing, Wamsutter sold $101.2 million of NGLs to a subsidiary of Williams that purchases substantially all of the NGLs and excess natural gas to which Wamsutter takes title based on market pricing and Discovery sold $217.0 million of products to a subsidiary of Williams that purchases substantially all of the NGLs and excess natural gas to which Discovery takes title based on market pricing.
In December 2007 and January 2008, we entered into financial swap contracts with Williams affiliates to hedge 5.4 million gallons of forecasted NGL sales monthly for February through December 2008 with a range of fixed prices of $0.86 to $2.08 per gallon depending on the specific product.
Gathering, Processing and Treating Contracts
We maintain two contracts with an affiliate of Williams, a gas gathering and treating contract and a gas gathering and processing contract. Pursuant to the gas gathering and treating contract, our Four Corners system gathers and treats coal seam gas delivered by the affiliate to our Four Corners’ gathering systems. Deliveries of gas under this agreement averaged approximately 34 MMcf/d during 2007. The term of this agreement expires on December 31, 2022, but will continue thereafter on a year-to-year basis subject to termination by either party giving at least six months written notice of termination prior to the expiration of each one year period
Pursuant to gas gathering and processing contracts, our Four Corners system gathers and processes conventional and coal seam gas delivered by the affiliate to our Four Corners gathering systems. Deliveries of gas under these agreements averaged approximately 105 MMcf/d during 2007. The primary terms of these agreements ended on March 1, 2004, but continue to remain in effect on a year-to-year basis subject to termination by either party giving at least three months written notice of termination prior to the expiration of each one-year period.
Revenues recognized pursuant to these contracts totaled $35.8 million in 2007.
Natural Gas Purchases
We, Wamsutter and Discovery purchase natural gas primarily for fuel and shrink replacement from Williams Gas Marketing, an affiliate of Williams. These purchases are made at current market prices. For Four Corners, we purchased approximately $101.9 million of natural gas from Williams Gas Marketing during 2007. Wamsutter purchased approximately $32.0 million and Discovery purchased approximately $43.8 million of natural gas for fuel and shrink replacement from Williams Gas Marketing during 2007.
Four Corners uses waste heat from a co-generation plant located adjacent to the Milagro treating plant. The co-generation plant is owned by an affiliate of Williams, Williams Flexible Generation, LLC. Waste heat is required for the natural gas treating process, which occurs at Milagro. The charge to us for the waste heat is based on the natural gas needed to generate this waste heat. We purchase this natural gas from Williams Gas Marketing. Included in the $101.9 million presented in the immediately preceding paragraph is $19.6 million of natural gas purchases made to pursuant to this arrangement.
For the year ended December 31, 2007 we purchased a gross amount of $15.3 million of natural gas for our Conway fractionator from an affiliate of Williams.
In December 2007, we entered into fixed price natural gas purchase contracts with Williams Gas Marketing to hedge the price of our natural gas shrink replacement costs for 13.3 BBtu/d at a range of fixed prices from $6.59 to $7.17 per MMBtu.
Balancing Services Agreement
We maintain a balancing services contract with Williams Gas Marketing, an affiliate of Williams. Pursuant to this agreement, Williams Gas Marketing balances deliveries of natural gas processed by us
between certain points on our Four Corners gathering system. We determine on a daily basis the volumes of natural gas to be moved between gathering systems at established interconnect points to optimize flow, an activity referred to as “crosshauling.” Under the balancing services contract, Williams Gas Marketing purchases gas for delivery to customers at certain plant outlets and sells such volumes at other designated plant outlets to implement the crosshaul. These purchase and sales transactions are conducted for us by Williams Gas Marketing at current market prices. Historically, Williams Gas Marketing has not charged a fee for providing this service, but has occasionally benefited from price differentials that historically existed from time to time between the designated plant outlets. The revenues and costs related to the purchases and sales pursuant to this arrangement have historically tended to offset each other. The term of this agreement will expire upon six months or more written notice of termination from either party. To date, neither party has provided six months notice to terminate the agreement.
Summary of Other Transactions with Williams
For the year ended December 31, 2007:
•
we distributed $23.7 million to affiliates of Williams as quarterly distributions on their common units, subordinated units, 2% general partner interest and incentive distribution rights; and
•
we purchased $11.3 million of NGLs to replenish deficit product positions from a subsidiary of Williams based on market pricing.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including Williams, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner, which is comprised of independent directors. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:
•
approved by the conflicts committee;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires. See “Directors, Executive Officers and Corporate Governance - Governance - Board Committees - Conflict Committee.”
In addition, our code of business conduct and ethics requires that all employees, including employees of affiliates of Williams who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us and our unitholders.
Conflicts of interest that cannot be avoided must be disclosed to a supervisor who is then responsible for establishing and monitoring procedures to ensure that we are not disadvantaged.
Director Independence
Please read “Directors, Executive Officers and Corporate Governance - Governance - Director Independence” above for information about the independence of our general partner’s board of directors and its committees, which information is incorporated herein by reference in its entirety.
Item 14.
Item 14.
Principal Accountant Fees and Services
Fees for professional services provided by our independent auditors, Ernst & Young LLP, for each of the last two fiscal years in each of the following categories are:
Fees for audit services in 2007 and 2006 include fees associated with the annual audit, the reviews of our quarterly reports on Form 10-Q and services provided in connection with other filings with the SEC. The fees for audit services do not include audit costs for stand-alone audits for equity investees, including Discovery or Wamsutter. Tax fees for 2007 and 2006 include fees for review of our federal tax return. The audit fees for 2007 and 2006 included in the table above include $0.3 million and $0.4 million, respectively, for services provided in connection with the acquisition of interests in Discovery, Wamsutter and Four Corners.
The audit committee of our general partner has established a policy regarding pre-approval of all audit and non-audit services provided by Ernst & Young LLP. On an ongoing basis, our general partner’s management presents specific projects and categories of service to our general partner’s audit committee for which advance approval is requested. The audit committee reviews those requests and advises management if the audit committee approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of our general partner reports to the audit committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The audit committee may also delegate the ability to pre-approve permissible services, excluding services related to our internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported at a subsequent audit committee meeting. In 2007, 100% of Ernst & Young LLP’s fees were pre-approved by the audit committee. The audit committee’s pre-approval policy with respect to audit and non-audit services is provided as an exhibit to this report.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) 1 and 2. Williams Partners L.P. financials
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) 3 and (b). The exhibits listed below are furnished or filed as part of this annual report:
The exhibits listed below are filed as part of this annual report:
*
Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
+
Filed herewith.
§
Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
#
Management contract or compensatory plan or arrangement.
(c)
Wamsutter LLC financial statements and notes thereto
Discovery Producer Services LLC financial statements and notes thereto
Report of Independent Auditors
To the Management Committee of
Wamsutter LLC
We have audited the accompanying balance sheets of Wamsutter LLC as of December 31, 2007 and 2006, and the related statements of income, members’ capital, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the 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 Wamsutter LLC’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 Wamsutter LLC’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 Wamsutter LLC at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 in conformity with U.S. generally accepted accounting principles.
As described in Note 5, effective December 31, 2005, Wamsutter LLC adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2008
WAMSUTTER LLC
BALANCE SHEETS
See accompanying notes to financial statements.
WAMSUTTER LLC
STATEMENTS OF INCOME
See accompanying notes to financial statements.
WAMSUTTER LLC
STATEMENT OF MEMBERS’ CAPITAL
*
Williams and Williams Partners each have 20 Class C units
See accompanying notes to financial statements.
WAMSUTTER LLC
STATEMENTS OF CASH FLOWS
See accompanying notes to financial statements.
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS
Note 1.
Basis of Presentation
References in this report to “we,” “our,” “us” or like terms refer to Wamsutter LLC. The accompanying financial statements and related notes present the financial position, results of operations, cash flows and members’ capital of a natural gas gathering and processing system in Wyoming previously held by Williams Field Services Company, LLC (WFSC). This system is collectively referred to as the “Wamsutter” system. WFSC is a wholly owned subsidiary of The Williams Companies, Inc (Williams). In June 2007, WFSC formed a new entity, Wamsutter LLC. On December 11, 2007, the Wamsutter assets were conveyed by WFSC into Wamsutter LLC in connection with the acquisition of certain ownership interests in Wamsutter LLC by Williams Partners L.P. (the Partnership). Pursuant to that acquisition effective December 1, 2007, the Partnership owns 100% of our Class A membership interests and 50% of our initial Class C units (or 20 Class C units). WFSC owns 100% of our Class B membership interests and the remaining 50% of our initial Class C units (or 20 Class C units). See Note 8, “Members’ Capital”, for more information about these different forms of ownership.
Note 2.
Description of Business
We operate a natural gas gathering and processing system in Wyoming. This gathering and processing system includes natural gas gathering pipelines and a processing plant. The system includes approximately 1,700 miles of natural gas gathering pipelines with typical operating capacity of approximately 500 million cubic feet per day (MMcfd) at current operating pressures. The system has total compression of approximately 70,000 horsepower. The assets include the Echo Springs natural gas processing plant, which has an inlet capacity of 390 million cubic feet per day and can produce approximately 30,000 barrels per day (bpd) of natural gas liquids (NGLs).
Note 3.
Summary of Significant Accounting Policies
Basis of Presentation. The financial statements have been prepared based upon accounting principles generally accepted in the United States. Intercompany accounts and transactions have been eliminated.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include asset retirement obligations. These estimates are discussed further in the accompanying notes.
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue which generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.
Product Imbalances. In the course of providing gathering and processing services to our customers, we realize over and under deliveries of our customers’ products, and over and under purchases of shrink replacement gas when our purchases vary from operational requirements. In addition, we realize gains and losses which we believe are related to inaccuracies inherent in the gas measurement process. These items are reflected as product imbalance receivables and payables on the Balance Sheets. Product imbalance receivables
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
are valued based on the lower of the current market prices or current cost of natural gas in the system. Product imbalance payables are valued at current market prices. The majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately settled in cash and are generally negotiated at values which approximate average market prices over a period of time. These gains and losses impact our results of operations and are included in operating and maintenance expense in the Statements of Income.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on capitalized costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided on a straight-line basis over estimated useful lives. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that extend the useful lives of the assets or increase their functionality are capitalized. The cost of property, plant and equipment sold or retired and the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recorded in operating income.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of products are recognized when the product has been delivered, and revenues from the gathering and processing of gas are generally recognized in the period the service is provided, based on contractual terms and the related natural gas and liquid volumes. One gathering agreement provides incremental fee-based revenues upon the completion of projects that lower system pressures. This revenue is recognized on a units-of-production basis as gas is produced under this agreement. Additionally, revenue from customers for the installation and operation of electronic flow measurement equipment is recognized evenly over the life of the underlying agreements.
Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by the individual members through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of members as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Recent Accounting Standards. In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements.” This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In December 2007, the FASB issued proposed FASB Staff Position (FSP) No. FAS 157-b deferring the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. On January 1, 2008, we adopted SFAS No. 157 applying a prospective transition for our assets and liabilities that are measured at fair value on a recurring basis with no material impact to our Consolidated Financial Statements. SFAS No. 157 expands disclosures about assets and liabilities measured at fair value on a recurring basis effective beginning with the first-quarter 2008 reporting.
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115.” SFAS No. 159 establishes a fair value option permitting entities to elect to measure eligible financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, is irrevocable and is applied only to the entire instrument. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007, and should not be applied retrospectively to fiscal years beginning prior to the effective date. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. Subsequent to January 1, 2008, the fair value option can only be elected when a financial instrument or certain other item is entered into. On January 1, 2008, we adopted SFAS No. 159 but have not elected the fair value option for any existing eligible financial instruments or other items.
Note 4.
Related Party Transactions
The employees supporting our operations are employees of Williams. Their payroll costs are directly charged to us by Williams. Williams carries the accruals for most employee-related liabilities in its financial statements, including the liabilities related to the employee retirement and medical plans and paid time off accruals. Our share of these costs is charged to us through a benefit load factor with the payroll costs and are reflected in Operating and maintenance expense - Affiliate in the accompanying Statements of Income.
We purchase natural gas for fuel and shrink replacement from Williams Gas Marketing (WGM), a wholly owned indirect subsidiary of Williams. These purchases are made at market rates at the time of purchase. These costs are reflected in Operating and maintenance expense - Affiliate and Product cost - Affiliate in the accompanying Statements of Income.
A summary of affiliate operating and maintenance expenses directly charged to us for the periods stated is as follows:
We are charged for certain administrative expenses by Williams and its Midstream segment of which we are a part. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams and Midstream at our request. Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are allocated to us. These expenses are allocated based on a three-factor formula, which considers revenues, property, plant and equipment and payroll. These costs are reflected in General and administrative expenses - Affiliate in the accompanying Statements of Income. 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 and its Midstream segment.
We sell the NGLs to which we take title to Williams NGL Marketing LLC (WNGLM), a wholly owned indirect subsidiary of Williams. Revenues associated with these activities are reflected as Product sales - affiliate on the Statements of Income. These sales are made at market rates at the time of sale.
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
We participate in Williams’ cash management program; hence, we maintain no cash balances. Prior to December 1, 2007, our net advances to Williams under an unsecured promissory note agreement which allowed for both advances to and from Williams were classified as a component of members’ capital because, although the advances were due on demand, Williams had not historically required repayment or repaid amounts owed to us. Changes in the advances to Williams are presented as distributions to Williams in the Statement of Members’ Capital and Statements of Cash Flows. As of December 1, 2007 these net advances to Williams are included in Accounts receivable - Affiliate. As of December 31, 2007 we had a receivable of $1.3 million. Interest is paid to us on amounts receivable from Williams’ under the cash management program based on the rate received by Williams on the overnight investment of its excess cash.
Note 5.
Property, Plant and Equipment
Property, plant and equipment, at cost, is as follows:
Effective December 31, 2005, we adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling approximately $57,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $9,000 increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $48,000 reduction to earnings is reflected as a cumulative effect of change in accounting principle for the year ended 2005.
Our ARO at December 31, 2007 and 2006 is approximately $0.2 million. The obligations relate to gas processing and compression facilities located on leased land and wellhead connections on federal land. At the end of the useful life of each respective asset, we are legally or contractually obligated to remove certain surface equipment and cap certain gathering pipelines at the wellhead connection.
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
Note 6.
Accrued Liabilities
Accrued liabilities are as follows:
Note 7.
Credit Facilities and Leasing Activities
On December 11, 2007, we entered into a $20.0 million revolving credit facility with Williams as the lender. The credit facility is available to fund working capital requirements and for other purposes. Borrowings under the credit facility mature on December 9, 2008 and bear interest at the one-month LIBOR. We pay a commitment fee to Williams on the unused portion of the credit facility of 0.175% annually. As of December 31, 2007, we had no outstanding borrowings under the credit facility.
We lease the land on which a significant portion of our pipeline assets are located. The primary landowner is the Bureau of Land Management (BLM). The BLM leases are for thirty years with renewal options. In 2005, we also began leasing two compression units under a five-year agreement. Under the terms of this lease agreement, we have guaranteed the residual value of the compression units in the event of a casualty loss. The guarantee has a maximum potential exposure at December 31, 2007 of $5.7 million. The recorded carrying value of this guarantee was $0.2 million and $0.3 million at December 31, 2007 and 2006, respectively. We also lease vehicles under non-cancelable leases, which are for lease terms of about 45 months. These leases are accounted for as operating leases. The future minimum annual rentals under these non-cancelable leases as of December 31, 2007 are payable as follows:
Total rent expense for the years ended 2007, 2006 and 2005 was $2.0 million, $1.7 million and $0.7 million, respectively.
Note 8.
Members’ Capital
Governance. Most decisions regarding our day to day operations are made by Williams, in its capacity as the Class B member. However, certain decisions require the consent of the Class A member, including, but not limited to, (i) the sale or disposition of assets over $20.0 million, (ii) the merger or consolidation with another entity, (iii) the purchase or acquisition of assets or businesses, (iv) the making of an investment in a third party in excess of $20.0 million, (v) the guarantee or incurrence of any debt, (vi) the cancelling or settling of any claim in excess of $20.0 million, (vii) the selling or redeeming of any equity interests in us,
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
(viii) the declaration of distributions not described below, (ix) the entering into certain transactions outside the ordinary course of business with our affiliates and (x) the approval of our annual business plan. Williams also controls the Class A member through its ownership of the Class A member’s general partner.
Distributions. Our limited liability company (LLC) agreement provides for distributions of available cash to be made quarterly. We distribute our available cash as follows:
•
First, an amount equal to $17.5 million per quarter to the holder of our Class A membership interests;
•
Second, an amount to the holder of our Class A membership interests, if any, needed to increase the distribution on our Class A membership interests in prior quarters of the current distribution year to $17.5 million per quarter; and
•
Third, 5% of remaining available cash shall be distributed to the holder of our Class A membership interests and 95% shall be distributed to the holders of our Class C units, on a pro rata basis.
In addition, to the extent that at the end of the fourth quarter of a distribution year, our Class A member has received less than $70.0 million under the first and second bullets above, our Class C members will be required to repay any distributions they received in that distribution year such that our Class A member receives $70.0 million for that distribution year. If this repayment is insufficient to result in the Class A member receiving $70.0 million, the shortfall will not carry forward to the next distribution year. Our initial distribution year for Wamsutter began on December 1, 2007 and will end on November 30, 2008. Subsequent distribution years for Wamsutter will commence on December 1 and end on November 30.
Our LLC agreement provides each quarter during 2008 through 2012, that we will receive a transition support payment, related to a cap on general and administrative expenses, from our Class B ownership interest. This payment will be distributed directly to our Class A ownership interest. The reimbursement will be treated as a capital contribution by our Class B member and the cost subject to this reimbursement will be allocated entirely to our Class B member.
Income Allocation. The allocation of our net income is based upon the allocation and distribution provisions of our LLC agreement. In general, the agreement allocates income to the Class A, B and C ownership interest in a manner that will maintain capital account balances reflective of the amounts each ownership interest would receive if we were dissolved and liquidated at our carrying value. In general, income allocations follow the provisions of our LLC agreement for the distribution of our available cash.
Contributions for Capital Expenditures. We fund expansion capital expenditures through capital contributions from our members as specified in our LLC agreement. The agreement specifies that expansion capital expenditures with expected total expenditures in excess of $2.5 million at the time of approval and well connections that grow gathered volumes as defined in our LLC agreement be funded by contributions from our Class B membership. Our Class A membership interest will provide capital contributions related to expansion projects with expected total expenditures less than $2.5 million at the time of approval. On the first day of the quarter following the quarter the asset related to these expansion capital expenditures is placed in service, we will issue to each contributing member one Class C unit for each $50,000 contributed by it, including the interest accrued on the investment prior to the issuance of the Class C units. We will issue fractional Class C units as necessary.
Note 9.
Major Customers and Concentrations of Credit Risk
At December 31, 2007 and 2006, substantially all of our accounts receivable result from product sales and gathering and processing services provided to our five largest customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS - (Continued)
required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables.
Our largest customer, on a percentage of revenues basis, is WNGLM, which purchases and resells substantially all of the NGLs to which we take title. WNGLM accounted for 56%, 66% and 72% of revenues in 2007, 2006 and 2005, respectively. The percentages for the remaining two largest customers are as follows:
Note 10.
Commitments and Contingencies
Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held on April 1, 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.
Grynberg. In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, including us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the Department of Justice announced that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against us. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including us, be dismissed. On October 20, 2006, the court dismissed all claims against us. In November 2006, Grynberg filed his notice of appeals with the Tenth Circuit Court of Appeals. The amount of any possible liability cannot be reasonably estimated at this time.
Report of Independent Registered Public Accounting Firm
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as of December 31, 2007 and 2006, and the related consolidated statements of income, members’ capital, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 consolidated financial position of Discovery Producer Services LLC at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As described in Note 4, effective December 31, 2005, Discovery Producer Services LLC adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2008
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes to consolidated financial statements.
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL
See accompanying notes to consolidated financial statements.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
Organization and Description of Business
Our company consists of Discovery Producer Services LLC, or DPS, a Delaware limited liability company formed on June 24, 1996, and its wholly owned subsidiary, Discovery Gas Transmission LLC, or DGT, a Delaware limited liability company also formed on June 24, 1996. DPS was formed for the purpose of constructing and operating a 600 million cubic feet per day (MMcf/d) cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day (bpd) natural gas liquids fractionator plant near Paradis, Louisiana. DGT was formed for the purpose of constructing and operating a natural gas pipeline from offshore deep water in the Gulf of Mexico to DPS’s gas processing plant in Larose, Louisiana. The pipeline has a design capacity of 600 MMcf/d and consists of approximately 173 miles of pipe. DPS has since connected several laterals to the DGT pipeline to expand its presence in the Gulf. Herein, DPS and DGT are collectively referred to in the first person as “we,” “us” or “our” and sometimes as “the Company”.
Until April 14, 2005, we were owned 50% by Williams Energy, L.L.C. (a wholly owned subsidiary of The Williams Companies, Inc.), 33.33% by DCP Assets, LP (DCP) formerly Duke Energy Field Services, LLC, and 16.67% by Eni BB Pipeline, LLC (Eni). Williams Energy, L.L.C. is our operator. Herein, The Williams Companies, Inc. and its subsidiaries are collectively referred to as “Williams.”
On April 14, 2005, Williams acquired the 16.67% ownership interest in us, which was previously held by Eni. As a result, we became 66.67% owned by Williams and 33.33% owned by DCP.
On August 23, 2005, Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners L.P. (WPZ) acquired a 40% interest in us, which was previously held by Williams. In connection with this acquisition, Williams, DCP and WPZ amended our limited liability company agreement including provisions for (1) quarterly distributions of available cash, as defined in the amended agreement and (2) pursuit of capital projects for the benefit of one or more of our members when there is not unanimous consent. On December 22, 2005, DCP acquired a 6.67% interest in us, which was previously held by Williams. On June 28, 2007, WPZ acquired an additional 20% interest in us from Williams. At December 31, 2007, we are owned 60% by WPZ and 40% by DCP.
Note 2.
Summary of Significant Accounting Policies
Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of DPS and its wholly owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated.
Reclassifications. Certain prior year amounts have been reclassified to conform with the current year presentation.
Use of Estimates. The preparation of consolidated 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 consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions used in the calculation of asset retirement obligations are, in the opinion of management, significant to the underlying amounts included in the consolidated financial statements. It is reasonably possible that future events or information could change those estimates.
Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.
Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
based on existing economic conditions, the financial condition of the customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. There was no allowance for doubtful accounts at December 31, 2007 and 2006.
Insurance Receivable. Expenditures incurred for the repair of the pipeline and onshore facilities damaged by Hurricane Katrina in 2005 and damage to the Tahiti steel catenary riser (SCR), which are probable of recovery when incurred, are recorded as insurance receivable. Expenditures up to the insurance deductible and amounts subsequently determined not to be recoverable are expensed.
Gas Imbalances. In the course of providing transportation services to customers, DGT may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables which are recovered or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the future. Imbalance receivables and payables are included in Other current assets and Other current liabilities in the Consolidated Balance Sheets. Imbalance receivables are valued based on the lower of the current market prices or current cost of natural gas in the system. Imbalance payables are valued at current market prices. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and the timing of delivery of gas based on operational conditions. In accordance with its tariff, DGT is required to account for this imbalance (cash-out) liability/receivable and refund or invoice the excess or deficiency when the cumulative amount exceeds $400,000. To the extent that this difference, at any year end, is less than $400,000, such amount would carry forward and be included in the cumulative computation of the difference evaluated at the following year end.
Inventory. Inventory includes fractionated products at our Paradis facility and is carried at the lower of cost or market.
Restricted Cash. Restricted cash within non-current assets relates to escrow funds contributed by our members for the construction of the Tahiti pipeline lateral expansion. The restricted cash is classified as non-current because the funds will be used to construct a long-term asset. The restricted cash is primarily invested in short-term money market accounts with financial institutions.
Property, Plant, and Equipment. Property, plant, and equipment are carried at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant, and equipment.
Depreciation of DPS’s facilities and equipment is computed primarily using the straight-line method with 25-year lives. Depreciation of DGT’s facilities and equipment is computed using the straight-line method with 15-year lives.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of products are recognized in the period of delivery and revenues from the gathering, transportation and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes. DGT is subject to Federal Energy Regulatory Commission (FERC) regulations, and accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
regulatory proceedings by DGT and other third parties, advice of counsel, and estimated total exposure as discounted and risk weighted, as well as collection and other risks. There were no rate refund liabilities accrued at December 31, 2007 or 2006.
Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an individual asset or asset group basis when events or changes in circumstances indicate that, in our management’s judgment, the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value is recoverable. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
Accounting for Repair and Maintenance Costs. We expense the cost of maintenance and repairs as incurred. Expenditures that enhance the functionality or extend the useful lives of the assets are capitalized and depreciated over the remaining useful life of the asset.
Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial statements.
Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains or losses which are reflected in the Consolidated Statements of Income.
Recent Accounting Standards. In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements”. This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. In December 2007, the FASB issued proposed FASB Staff Position No. FAS 157-b deferring the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. On January 1, 2008, we adopted SFAS No. 157 with no impact to our Consolidated Financial Statements. SFAS No. 157 expands disclosures about assets and liabilities measured at fair value on a recurring basis effective beginning with the first quarter 2008 reporting.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115”. SFAS No. 159 establishes a fair value option permitting entities to elect to measure eligible financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, is irrevocable and is applied only to the entire instrument. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007, and should not be applied retrospectively to fiscal years beginning prior to the effective date. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. Subsequent to
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
January 1, 2008, the fair value option can only be elected when a financial instrument or certain other item is entered into. On January 1, 2008, we adopted SFAS No. 159 but did not elect the fair value option for any existing eligible financial instruments or other items.
Note 3.
Related Party Transactions
We have various business transactions with our members and subsidiaries and affiliates of our members. Revenues include the following:
•
sales to Williams of NGLs to which we take title and excess gas at current market prices for the products,
•
processing and sales of natural gas liquids and transportation of gas and condensate for DCP’s affiliates, Texas Eastern Corporation and ConocoPhillips Company,
•
and processing and transportation of gas and condensate for Eni.
The following table summarizes these related-party revenues during 2007, 2006 and 2005.
*
Through April 14, 2005
We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with Williams. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Operating and maintenance expenses- affiliate includes the following:
•
direct payroll and employee benefit costs incurred on our behalf by Williams,
•
and rental expense resulting from a 10-year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP (an affiliate of DCP), as part of our market expansion project which began in June 2005.
Product costs and shrink replacement- affiliate includes natural gas purchases from Williams for fuel and shrink requirements made at market rates at the time of purchase.
General and administrative expenses - affiliate includes a monthly operation and management fee paid to Williams to cover the cost of accounting services, computer systems and management services provided to us.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and is capitalized as part of the construction costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows:
Note 4.
Property, Plant, and Equipment
Property, plant, and equipment consisted of the following at December 31, 2007 and 2006:
Commitments for construction and acquisition of property, plant, and equipment for the Tahiti pipeline lateral expansion are approximately $9 million at December 31, 2007.
Effective December 31, 2005, we adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $327,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $151,000 increase in property, plant, and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $176,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005.
Our obligations relate primarily to our offshore platform and pipelines and our onshore processing and fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platform, properly abandon the offshore pipelines, remove the onshore facilities and related surface equipment and restore the surface of the property.
A rollforward of our asset retirement obligation for 2007 and 2006 is presented below.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 5.
Leasing Activities
We lease the land on which the Paradis fractionator plant and the Larose processing plant are located. The initial term of each lease is 20 years with renewal options for an additional 30 years. We entered into a ten-year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP, as part of our market expansion project which began in June 2005. The lease includes renewal options and options to increase capacity which would also increase rentals. The future minimum annual rentals under these non-cancelable leases as of December 31, 2007 are payable as follows:
Total rent expense for 2007, 2006 and 2005, including a cancelable platform space lease and month-to-month leases, was $1.4 million, $1.4 million and $1.1 million, respectively.
Note 6.
Financial Instruments and Concentrations of Credit Risk
Financial Instruments Fair Value
We used the following methods and assumptions to estimate the fair value of financial instruments:
Cash and cash equivalents. The carrying amounts reported in the consolidated balance sheets approximate fair value due to the short-term maturity of these instruments.
Restricted cash. The carrying amounts reported in the consolidated balance sheets approximate fair value as these instruments have interest rates approximating market.
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Concentrations of Credit Risk
Our cash equivalents and restricted cash consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor’s or Aa by Moody’s Investor’s Service.
At December 31, 2007 and 2006, substantially all of our customer accounts receivable result from gas transmission services for and natural gas liquids sales to our two largest customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on receivables during 2007 and 2006.
Major Customers. Williams accounted for approximately $217.0 million (83%), $149.0 million (75%), $70.8 million (58%) respectively, of our total revenues in 2007, 2006 and 2005.
Note 7.
Rate and Regulatory Matters and Contingent Liabilities
Rate and Regulatory Matters. Annually, DGT files a request with the FERC for a lost-and-unaccounted-for gas percentage to be allocated to shippers for the upcoming fiscal year beginning July 1. On May 31, 2007, DGT filed to maintain a lost-and-unaccounted-for percentage of zero percent for the period July 1, 2007 to June 30, 2008 and to retain the 2006 net system gains of $1.8 million that are unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June 28, 2007 the filing was approved. The approval was subject to a 30 day protest period, which passed without protest. As of December 31, 2007, and 2006, DGT has deferred amounts of $5.8 million and $4.4 million, respectively, included in current accrued liabilities in the accompanying Consolidated Balance Sheets representing amounts collected from customers pursuant to prior years’ lost and unaccounted for gas percentage and unrecognized net system gains.
On November 25, 2003, the FERC issued Order No. 2004 promulgating new standards of conduct applicable to natural gas pipelines. On August 10, 2004, the FERC granted DGT a partial exemption allowing the continuation of DGT’s current ownership structure and management subject to compliance with many of the other standards of conduct. On November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004 as applied to interstate natural gas pipelines and their affiliates. On January 9, 2007, the FERC issued an Interim Rule. The Interim Rule re-promulgates, on an interim basis, the standards of conduct that were not challenged before the Court. The Interim Rule applies to the relationship between interstate natural gas pipelines and their marketing and brokering affiliates, but not necessarily to their other affiliates, such as gatherers, processors or exploration and production companies. On March 21, 2007 the FERC issued an Order on Clarification and Rehearing of the Interim Rule. The FERC clarified that the interim standards of conduct only apply to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on such natural gas transmission provider’s pipeline. Currently DGT’s marketing or brokering affiliates do not conduct transmission transactions on DGT. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking to propose permanent regulations regarding the standards of conduct. Comments were due April 4, 2007. The FERC may enact a final rule at any time. At this stage, it cannot be determined how a final rule may or may not affect us (or DGT).
On November 16, 2007, DGT filed a petition for approval of settlement in lieu of a general rate change filing with FERC. FERC issued a Notice of DGT’s filing setting a deadline for comments on November 27, 2007. One shipper, ExxonMobil, filed a protest. On December 3, DGT filed a response to ExxonMobil’s protest. On December 18, ExxonMobil filed a Motion for Leave to Answer and Answer and DGT responded
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
on December 20. On February 5, 2008 the FERC issued an order approving the settlement as to all parties except the protesting ExxonMobil Gas & Power Marketing Company. The order is subject to rehearing until March 6, 2008. The settlement is not final until the order is final and no longer subject to rehearing.
Pogo Producing Company. On January 16, 2006, DPS and DGT received notice of a claim by Pogo Producing Company (Pogo) relating to the results of a Pogo audit performed first in April 2004 and then continued through August 2005. Pogo claimed that DPS and DGT overcharged Pogo and its working interest owners approximately $600,000 relating to condensate transportation and handling during 2000 - 2005. The underlying agreements limit audit claims to a two-year period from the date of the audit. DPS and DGT disputed the validity of the claim. On November 2, 2007, the claim was settled for $300,000. In connection with the settlement, Pogo assigned production module equipment to us, and we assumed the associated asset retirement obligation. No gain or loss was recognized.
Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any noncompliance under the various environmental laws and regulations.
Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. Litigation, arbitration and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our future financial position.
Note 8.
Subsequent Events
On January 30, 2008, we made quarterly cash distributions totaling $28.0 million to our members.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Williams Partners L.P.
(Registrant)
By:
Williams Partners GP LLC,
its general partner
By:
/s/ William H. Gault
William H. Gault
Attorney-in-fact
Date: February 26, 2008
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 and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
*
Each such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
+
Filed herewith.
§
Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.
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Management contract or compensatory plan or arrangement.