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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2008
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-32599
WILLIAMS PARTNERS L.P.
(Exact Name of Registrant as Specified in its Charter)
DELAWARE | 20-2485124 | |
(State or other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) | |
ONE WILLIAMS CENTER TULSA, OKLAHOMA | 74172-0172 | |
(Address of principal executive offices) | (Zip Code) |
(918) 573-2000
(Registrant’s telephone number, including area code)
(Registrant’s telephone number, including area code)
NO CHANGE
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filerþ Accelerated filero Non-accelerated filero Smaller reporting companyo
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
The registrant had 52,774,728 common units outstanding as of April 30, 2008.
WILLIAMS PARTNERS L.P.
INDEX
INDEX
FORWARD-LOOKING STATEMENTS
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:
• | amounts and nature of future capital expenditures; | ||
• | expansion and growth of our business and operations; | ||
• | business strategy; | ||
• | cash flow from operations; | ||
• | seasonality of certain business segments; and | ||
• | 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. Many of the factors that will determine these results 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:
• | 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. | ||
• | Lower natural gas and oil prices could adversely affect our fractionation and storage businesses. | ||
• | Our processing, fractionation and storage businesses could be affected by any decrease in natural gas liquids (NGL) prices or a change in NGL prices relative to the price of natural gas. | ||
• | 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. | ||
• | 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 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. | ||
• | 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 operation results. | ||
• | Discovery and Wamsutter may reduce their cash distributions to us in some situations. | ||
• | Discovery’s interstate tariff rates and terms and conditions are subject to review and possible adjustment by federal regulators, and are subject to changes in policy by federal regulators which could have a material adverse effect on our business and operating results. | ||
• | Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured. | ||
• | 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. | ||
• | 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. | ||
• | 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. | ||
• | Our future financial and operating flexibility may be adversely affected by restrictions in our debt agreements and by our leverage. | ||
• | 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. | ||
• | Common units held by Williams eligible for future sale may have adverse effects on the price of our common units. | ||
• | 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. | ||
• | Even if unitholders are dissatisfied, they currently 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.
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. For a detailed discussion of those factors, see Part I, Item 1A “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2007, and Part II, Item 1A. Risk Factors of this quarterly report on Form 10-Q.
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PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per-unit amounts)
(Unaudited)
(Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2008 | 2007* | |||||||
Revenues: | ||||||||
Product sales: | ||||||||
Affiliate | $ | 78,122 | $ | 56,552 | ||||
Third-party | 4,221 | 6,313 | ||||||
Gathering and processing: | ||||||||
Affiliate | 8,790 | 9,491 | ||||||
Third-party | 46,210 | 51,103 | ||||||
Storage | 7,333 | 6,410 | ||||||
Fractionation | 3,292 | 1,917 | ||||||
Other | 2,394 | 2,029 | ||||||
Total revenues | 150,362 | 133,815 | ||||||
Costs and expenses: | ||||||||
Product cost and shrink replacement: | ||||||||
Affiliate | 22,033 | 21,725 | ||||||
Third-party | 30,065 | 20,470 | ||||||
Operating and maintenance expense (excluding depreciation): | ||||||||
Affiliate | 23,133 | 14,328 | ||||||
Third-party | 23,951 | 28,185 | ||||||
Depreciation, amortization and accretion | 11,226 | 13,178 | ||||||
General and administrative expense: | ||||||||
Affiliate | 9,876 | 9,406 | ||||||
Third-party | 928 | 664 | ||||||
Taxes other than income | 2,505 | 2,114 | ||||||
Other expense — net | 333 | 460 | ||||||
Total costs and expenses | 124,050 | 110,530 | ||||||
Operating income | 26,312 | 23,285 | ||||||
Equity earnings-Wamsutter | 21,194 | 11,328 | ||||||
Equity earnings-Discovery Producer Services | 13,621 | 3,931 | ||||||
Interest expense: | ||||||||
Affiliate | (25 | ) | (15 | ) | ||||
Third-party | (17,711 | ) | (14,375 | ) | ||||
Interest income | 238 | 983 | ||||||
Net income | $ | 43,629 | $ | 25,137 | ||||
Allocation of net income for calculation of earnings per unit: | ||||||||
Net income | $ | 43,629 | $ | 25,137 | ||||
Allocation of net income to general partner | 8,911 | 12,912 | ||||||
Allocation of net income to limited partners | $ | 34,718 | $ | 12,225 | ||||
Basic and diluted net income per limited partner unit: | ||||||||
Common units | $ | 0.66 | $ | 0.31 | ||||
Subordinated units | $ | 0.66 | $ | 0.31 | ||||
Weighted average number of units outstanding: | ||||||||
Common units | 49,005,497 | 32,358,798 | ||||||
Subordinated units | 3,769,231 | 7,000,000 |
* | Recast as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
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WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
March 31, | December 31, | |||||||
2008 | 2007 | |||||||
(Unaudited) | ||||||||
(In thousands) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 34,555 | $ | 36,197 | ||||
Accounts receivable: | ||||||||
Trade | 19,129 | 12,860 | ||||||
Affiliate | 33,036 | 20,402 | ||||||
Other | 3,852 | 2,543 | ||||||
Product imbalance | 15,600 | 20,660 | ||||||
Prepaid expense | 3,588 | 4,056 | ||||||
Derivative assets — affiliate | 1,488 | 231 | ||||||
Reimbursable projects | 3,555 | 8,989 | ||||||
Assets held for sale | 11,296 | 11,519 | ||||||
Other current assets | 3,727 | 3,574 | ||||||
Total current assets | 129,826 | 121,031 | ||||||
Investment in Wamsutter | 283,163 | 284,650 | ||||||
Investment in Discovery Producer Services | 211,783 | 214,526 | ||||||
Property, plant and equipment, net | 631,908 | 630,770 | ||||||
Other noncurrent assets | 30,426 | 32,500 | ||||||
Total assets | $ | 1,287,106 | $ | 1,283,477 | ||||
LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
Current liabilities: | ||||||||
Accounts payable: | ||||||||
Trade | $ | 36,208 | $ | 35,947 | ||||
Affiliate | 27,329 | 17,676 | ||||||
Product imbalance | 15,578 | 21,473 | ||||||
Deferred revenue | 1,266 | 4,569 | ||||||
Derivative liabilities — affiliate | 1,521 | 2,718 | ||||||
Accrued interest | 12,043 | 19,500 | ||||||
Other accrued liabilities | 8,872 | 8,243 | ||||||
Total current liabilities | 102,817 | 110,126 | ||||||
Long-term debt | 1,000,000 | 1,000,000 | ||||||
Environmental remediation liabilities | 2,321 | 2,599 | ||||||
Other noncurrent liabilities | 9,383 | 9,265 | ||||||
Commitments and contingent liabilities (Note 9) | ||||||||
Partners’ capital | 172,585 | 161,487 | ||||||
Total liabilities and partners’ capital | $ | 1,287,106 | $ | 1,283,477 | ||||
See accompanying notes to consolidated financial statements.
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WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2008 | 2007* | |||||||
(In thousands) | ||||||||
OPERATING ACTIVITIES: | ||||||||
Net income | $ | 43,629 | $ | 25,137 | ||||
Adjustments to reconcile to cash provided by operations: | ||||||||
Depreciation, amortization and accretion | 11,226 | 13,178 | ||||||
Amortization of gas purchase contract — affiliate | — | 1,188 | ||||||
Equity earnings of Wamsutter | (21,194 | ) | (11,328 | ) | ||||
Equity earnings of Discovery Producer Services | (13,621 | ) | (3,931 | ) | ||||
Distributions related to equity earnings of Wamsutter | 22,703 | — | ||||||
Distributions related to equity earnings of Discovery Producer Services | 13,621 | 2,620 | ||||||
Cash provided (used) by changes in assets and liabilities: | ||||||||
Accounts receivable | (20,212 | ) | (1,436 | ) | ||||
Prepaid expense | 467 | 1,188 | ||||||
Other current assets | 5,282 | (335 | ) | |||||
Accounts payable | 9,914 | 11,055 | ||||||
Product imbalance | (835 | ) | (183 | ) | ||||
Accrued liabilities | (7,214 | ) | 15,460 | |||||
Deferred revenue | (3,364 | ) | (3,012 | ) | ||||
Other, including changes in non-current liabilities | 1,120 | 215 | ||||||
Net cash provided by operating activities | 41,522 | 49,816 | ||||||
INVESTING ACTIVITIES: | ||||||||
Capital expenditures | (11,556 | ) | (9,766 | ) | ||||
Cumulative distributions in excess of equity earnings of Discovery Producer Services | 3,179 | 980 | ||||||
Change in accrued liabilities-capital expenditures | 108 | (1,430 | ) | |||||
Contributions to Wamsutter | (22 | ) | — | |||||
Contributions to Discovery Producer Services | (437 | ) | — | |||||
Net cash used by investing activities | (8,728 | ) | (10,216 | ) | ||||
FINANCING ACTIVITIES: | ||||||||
Distributions to unitholders | (35,283 | ) | (19,491 | ) | ||||
Proceeds from sale of common units | 28,992 | — | ||||||
Redemption of common units from general partner | (28,992 | ) | — | |||||
Contributions per omnibus agreement | 771 | 842 | ||||||
Other | 76 | — | ||||||
Net cash used by financing activities | (34,436 | ) | (18,649 | ) | ||||
Increase (decrease) in cash and cash equivalents | (1,642 | ) | 20,951 | |||||
Cash and cash equivalents at beginning of period | 36,197 | 57,541 | ||||||
Cash and cash equivalents at end of period | $ | 34,555 | $ | 78,492 | ||||
* | Recast as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
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WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)
(Unaudited)
Limited Partners | Accumulated Other | Total | ||||||||||||||||||
General | Comprehensive | Partners’ | ||||||||||||||||||
Common | Subordinated | Partner | Loss | Capital | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance — January 1, 2008 | $ | 1,473,814 | $ | 109,542 | $ | (1,419,382 | ) | $ | (2,487 | ) | $ | 161,487 | ||||||||
Net income | 37,359 | 1,556 | 4,714 | — | 43,629 | |||||||||||||||
Other comprehensive income (loss): | ||||||||||||||||||||
Net unrealized gains on cash flow hedges | — | — | — | 2,459 | 2,459 | |||||||||||||||
Reclassification into earnings of derivative instrument gains | — | — | — | (5 | ) | (5 | ) | |||||||||||||
Total other comprehensive income | 2,454 | |||||||||||||||||||
Total comprehensive income | 46,083 | |||||||||||||||||||
Cash distributions | (26,321 | ) | (4,025 | ) | (4,937 | ) | — | (35,283 | ) | |||||||||||
Conversion of subordinated units into common | 107,073 | (107,073 | ) | — | — | — | ||||||||||||||
Contributions pursuant to the omnibus agreement | — | — | 771 | — | 771 | |||||||||||||||
Issuance of units to public | 28,992 | — | — | — | 28,992 | |||||||||||||||
Repurchase of units from Williams | (28,992 | ) | — | — | — | (28,992 | ) | |||||||||||||
Other | (473 | ) | — | — | — | (473 | ) | |||||||||||||
Balance — March 31, 2008 | $ | 1,591,452 | $ | — | $ | (1,418,834 | ) | $ | (33 | ) | $ | 172,585 | ||||||||
See accompanying notes to consolidated financial statements.
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WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
Note 1. Organization and Basis of Presentation
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 principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing natural gas liquids (NGL). 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.
On June 28, 2007, we closed on the acquisition of an additional 20% interest in Discovery from Williams Energy, L.L.C. and Williams Energy Services, LLC, 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 The Williams Companies, Inc. (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. The effect of recasting our financial statements to account for this common control exchange increased net income $1.3 million for the first quarter of 2007. The acquisition had no impact on earnings per unit as pre-acquisition earnings were allocated to the general partner.
On December 11, 2007, we acquired certain 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) 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. The effect of recasting our financial statements to account for this common control exchange increased net income $11.3 million for the first quarter of 2007. This acquisition does not impact earnings per unit as pre-acquisition earnings were allocated to our general partner.
The accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K, filed February 26, 2008, for the year ended December 31, 2007. The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at March 31, 2008, and results of operations for the three months ended March 31, 2008 and 2007 and cash flows for the three months ended March 31, 2008 and 2007. All intercompany transactions have been eliminated. Certain amounts have been reclassified to conform to the current classifications.
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.
Note 2. Recent Accounting Standards
In March 2008, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 amends and expands the disclosure requirements of Statement 133 with
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enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments in the statement of financial position, gains and losses on derivative instruments in the statement of financial performance and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and non-hedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS No. 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will assess the application of this Statement on our disclosures in our consolidated financial statements.
In March 2008, the FASB ratified the decisions reached by the Emerging Issues Task Force (EITF) with respect to EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128,Earnings per Share,to Master Limited Partnerships.” EITF Issue No. 07-4 states, among other things, that the calculation of earnings per unit should not reflect an allocation of undistributed earnings to the incentive distribution right (IDR) holders beyond amounts distributable to IDR holders under the terms of the partnership agreement. As described in Note 3, under current generally accepted accounting principles, we calculate earnings per unit as if all the earnings for the period had been distributed, which results in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. Following the adoption of the guidance in EITF Issue No. 07-4, we will no longer calculate assumed incentive distributions. The final consensus is effective beginning with the first interim period of the fiscal year beginning after December 15, 2008, and must be retrospectively applied to all periods presented. Early application is prohibited. Retrospective application of this guidance will result in a decrease in the income allocated to the general partner and an increase in the income allocated to limited partners for the amount that any assumed incentive distribution exceeded the actual incentive distribution paid during that period. Certain of our historical periods’ earnings per unit will be revised as a result of this change. Adoption of this new standard only impacts the allocation of earnings for purposes of calculating our earnings per limited partner unit and will have no impact on our results of operations or distributions of available cash to unitholders and our general partner.
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Note 3. 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, is as follows (in thousands):
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
Allocation to general partner: | ||||||||
Net income | $ | 43,629 | $ | 25,137 | ||||
Net income applicable to pre-partnership operations allocated to general partner | — | (12,639 | ) | |||||
Reimbursable general and administrative costs charged directly to general partner | 398 | 592 | ||||||
Income subject to 2% allocation of general partner interest | 44,027 | 13,090 | ||||||
General partner’s share of net income | 2.0 | % | 2.0 | % | ||||
General partner’s allocated share of net income before items directly allocable to general partner interest | 881 | 262 | ||||||
Incentive distributions paid to general partner* | 4,231 | 603 | ||||||
Direct charges to general partner | (398 | ) | (592 | ) | ||||
Pre-partnership net income allocated to general partner | — | 12,639 | ||||||
Net income allocated to general partner | $ | 4,714 | $ | 12,912 | ||||
Net income | $ | 43,629 | $ | 25,137 | ||||
Net income allocated to general partner | 4,714 | 12,912 | ||||||
Net income allocated to limited partners | $ | 38,915 | $ | 12,225 | ||||
* | 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. There are $8.4 million of assumed incentive distributions for the three months ended March 31, 2008 and no assumed incentive distributions for the three months ended March 31, 2007. |
Common and subordinated unitholders have always shared equally, on a per-unit basis, in the net income allocated to limited partners.
We paid or have authorized payment of the following cash distributions during 2007 and 2008 (in thousands, except for per unit amounts):
General Partner | ||||||||||||||||||||||||||||
Incentive | ||||||||||||||||||||||||||||
Per Unit | Common | Subordinated | Class B | Distribution | Total Cash | |||||||||||||||||||||||
Payment Date | Distribution | Units | Units | Units | 2% | Rights | Distribution | |||||||||||||||||||||
2/14/2007 | $ | 0.4700 | $ | 12,010 | $ | 3,290 | $ | 3,198 | $ | 390 | $ | 603 | $ | 19,491 | ||||||||||||||
5/15/2007 | $ | 0.5000 | $ | 12,777 | $ | 3,500 | $ | 3,403 | $ | 421 | $ | 965 | $ | 21,066 | ||||||||||||||
8/14/2007 | $ | 0.5250 | $ | 16,989 | $ | 3,675 | — | $ | 447 | $ | 1,267 | $ | 22,378 | |||||||||||||||
11/14/2007 | $ | 0.5500 | $ | 17,799 | $ | 3,850 | — | $ | 487 | $ | 2,211 | $ | 24,347 | |||||||||||||||
2/14/2008 | $ | 0.5750 | $ | 26,321 | $ | 4,025 | — | $ | 706 | $ | 4,231 | $ | 35,283 | |||||||||||||||
5/15/2008(a) | $ | 0.6000 | $ | 31,665 | — | — | $ | 758 | $ | 5,498 | $ | 37,921 |
(a) | The board of directors of our general partner declared this cash distribution on April 24, 2008 to be paid on May 15, 2008 to unitholders of record at the close of business on May 7, 2008. |
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Note 4. Assets Held for Sale
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 on August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. The special business license requires the execution of a purchase and sale agreement for these gathering assets on or before May 31. It is anticipated that this sale will be completed during the third or fourth quarter of 2008. As a result of the maturation of negotiations during the first quarter of 2008, these assets have been classified as held for sale on the consolidated balance sheet and include property, plant and equipment. Our management believes the expected proceeds from the sale of these assets will substantially exceed their carrying value of $11.3 million. The gathering system assets being sold are part of the Gathering and Processing — West segment.
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Note 5. Equity Investments
We are allocated net income (equity earnings) from Wamsutter based upon the allocation, distribution, and liquidation provisions of its limited liability company agreement applied as though liquidation occurs at book value. In general, the agreement allocates income 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. The income allocation for the quarterly periods during a year reflects the preferential rights of the Class A interest to any distributions made to the Class C interest until the Class A interest has received $70.0 million in distributions for the year. The Class B interest receives no income or loss allocation. As the owner of 100% of the Class A ownership interest, we will receive 100% of Wamsutter’s net income up to $70.0 million. Income in excess of $70.0 million will be shared between the Class A interest and Class C interest, of which we currently own 50%. For annual periods in which Wamsutter’s net income exceeds $70.0 million, this will result in a higher allocation of equity earnings early in the year and a lower allocation of equity earnings later in the year. As such, equity earnings in the first quarter may not be representative of the remaining quarters of the year. Wamsutter’s net income allocations do not affect the amount of available cash it distributes for any quarter.
The summarized financial position and results of operations for 100% of Wamsutter are presented below (in thousands):
Wamsutter
March 31, | December 31, | |||||||
2008 | 2007 | |||||||
(Unaudited) | ||||||||
Current assets | $ | 35,405 | $ | 27,114 | ||||
Property, plant and equipment, net | 273,563 | 275,163 | ||||||
Non-current assets | 175 | 191 | ||||||
Current liabilities | (22,906 | ) | (12,944 | ) | ||||
Non-current liabilities | (2,867 | ) | (2,812 | ) | ||||
Members’ capital | $ | 283,370 | $ | 286,712 | ||||
Three Months Ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Unaudited) | ||||||||
Revenues: | ||||||||
Affiliate | $ | 50,050 | $ | 22,279 | ||||
Third-party | 17,575 | 17,894 | ||||||
Costs and expenses: | ||||||||
Affiliate | 33,214 | 16,174 | ||||||
Third-party | 13,217 | 12,671 | ||||||
Net income | $ | 21,194 | $ | 11,328 | ||||
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The summarized financial position and results of operations for 100% of Discovery are presented below (in thousands):
Discovery
March 31, | December 31, | |||||||
2008 | 2007 | |||||||
(Unaudited) | ||||||||
Current assets | $ | 75,773 | $ | 78,035 | ||||
Non-current restricted cash and cash equivalents | 3,641 | 6,222 | ||||||
Property, plant and equipment, net | 363,889 | 368,228 | ||||||
Current liabilities | (27,375 | ) | (33,820 | ) | ||||
Non-current liabilities | (12,450 | ) | (12,216 | ) | ||||
Members’ capital | $ | 403,478 | $ | 406,449 | ||||
Three Months Ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Unaudited) | ||||||||
Revenues: | ||||||||
Affiliate | $ | 78,006 | $ | 44,533 | ||||
Third-party | 9,150 | 7,948 | ||||||
Costs and expenses: | ||||||||
Affiliate | 38,246 | 23,155 | ||||||
Third-party | 26,620 | 24,120 | ||||||
Interest income | (264 | ) | (661 | ) | ||||
Gain on sale of operating assets | — | (468 | ) | |||||
Foreign exchange gain | (147 | ) | (216 | ) | ||||
Net income | $ | 22,701 | $ | 6,551 | ||||
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Note 6. Long-Term Debt and Credit Facilities
Long-Term Debt
Long-term debt at March 31, 2008 and December 31, 2007 is as follows:
Interest | March 31, | December 31, | ||||||||||
Rate | 2008 | 2007 | ||||||||||
(In millions) | ||||||||||||
Credit agreement term loan, adjustable rate, due 2012 | (a | ) | $ | 250 | $ | 250 | ||||||
Senior unsecured notes, fixed rate, due 2017 | 7.25 | % | 600 | 600 | ||||||||
Senior unsecured notes, fixed rate, due 2011 | 7.50 | % | 150 | 150 | ||||||||
Total Long-term debt | $ | 1,000 | $ | 1,000 | ||||||||
(a) | 4.10% at March 31, 2008. |
Credit Facilities
We have 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 March 31, 2008, we had a $250.0 million term loan outstanding under the term loan provisions and no amounts outstanding under the revolving credit 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. Borrowings under the credit facility will mature on June 20, 2009. 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 March 31, 2008, we had no outstanding borrowings under the working capital credit facility.
Note 7. Partners’ Capital
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 pursuant to our common unit offering in December 2007 used to finance our acquisition of the Wamsutter Ownership Interests. We used the net proceeds from the partial exercise of the underwriters’ option to redeem 800,000 common units from an affiliate of Williams at a price per common unit of $36.24 ($37.75, net of underwriter discount).
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.
Note 8. Fair Value Measurements
Adoption of SFAS No.157
SFAS No. 157, “Fair Value Measurements” (1) establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, (2) provides guidance on the methods used to estimate fair value and (3) expands disclosures about fair value measurements. On January 1, 2008, we adopted SFAS No. 157 for our assets and liabilities, which are measured at fair value on a recurring basis, primarily our energy commodity derivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our non-performance risk in estimating the fair value of our liabilities. The initial adoption of SFAS No. 157 had no material impact on our consolidated financial statements. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2 permitting entities to delay application of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS No. 157 fair value requirements to
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nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. 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 for all other instruments. Upon adopting SFAS No. 157, we applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.
Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We primarily apply a market approach for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs where possible.
SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
• | Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | ||
• | Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. | ||
• | Level 3 — Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. |
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
At March 31, 2008 all of our derivative assets and liabilities which are valued at fair value are included in Level 3 and include $1.5 million of energy commodity derivative assets and $1.5 million of energy commodity derivative liabilities. These derivatives include commodity based financial swap contracts.
The determination of fair value also incorporates factors such as including the credit standing of the counterparties involved, our nonperformance risk on our liabilities, the impact of credit enhancements (such as cash deposits and letters of credit) and the time value of money.
The following table sets forth a reconciliation of changes in the fair value of net derivatives classified as Level 3 in the fair value hierarchy for the period January 1, 2008 through March��31, 2008.
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Fair Value Measurements Using Significant Unobservable Inputs
(Level 3)
(In thousands)
(Level 3)
(In thousands)
Net Derivative | ||||
Asset (Liability) | ||||
Balance as of January 1, 2008 | $ | (2,487 | ) | |
Realized and unrealized gains (losses): | — | |||
Included in net income | — | |||
Included in other comprehensive income | 2,459 | |||
Purchases, issuances, and settlements | (5 | ) | ||
Transfers in/(out) of Level 3 | — | |||
Balance as of March 31, 2008 | $ | (33 | ) | |
Unrealized gains (losses) included in net income relating to instruments still held at March 31, 2008 | $ | — | ||
Realized and unrealized gains (losses) included in net income for the above period are reported in revenues in our Consolidated Statement of Income.
Note 9. Commitments and Contingencies
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 require 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 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.
In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued a Notice of Violation (NOV) 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.
In March 2008, the U.S. Environmental Protection Agency (EPA) proposed a penalty of $370 thousand for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant and for alleged permit violations at our Ute “E” compressor station. We met with the EPA and are exchanging information in order to resolve the issues.
We have accrued liabilities totaling $1.5 million at March 31, 2008 for these environmental activities. It is reasonably possible that we will incur losses 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, negotiations with the applicable agencies, and other factors.
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.
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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. There is also a three-year time limitation 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 March 31, 2008, we had accrued liabilities totaling $3.2 million for these costs. It is reasonably possible that we will incur losses 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 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 the 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, and 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, General 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 October 20, 2008. We are unable to quantify or estimate the possible liability.
Mid-America Pipeline Company.On April 28, 2008, Mid-America Pipeline Company, LLC (MAPL) filed suit in the District Court of Harris County, Texas seeking a declaration that NGLs from Wamsutter LLC's Echo Springs Plant must be delivered to MAPL for transportation through the life of the plant. An unfavorable ruling in this matter could result in higher, future transportation costs for Wamsutter LLC. The purported obligation arises under a Connection Agreement between Williams and MAPL, which allows Williams to terminate the Agreement upon proper notice. Williams has given MAPL notice of termination that will be effective May 5, 2008 and therefore denies any continuing obligation under the Connection Agreement.
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
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unfavorable ruling to occur, there exists the possibility of a material adverse effect on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect upon our future financial position.
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Note 10. 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.
Gathering & | ||||||||||||||||
Gathering & | Processing - | NGL | ||||||||||||||
Processing - West | Gulf | Services | Total | |||||||||||||
(In thousands) | ||||||||||||||||
Three Months Ended March 31, 2008: | ||||||||||||||||
Segment revenues | $ | 132,333 | $ | 567 | $ | 17,462 | $ | 150,362 | ||||||||
Product cost and shrink replacement | 47,446 | — | 4,652 | 52,098 | ||||||||||||
Operating and maintenance expense | 40,893 | 524 | 5,667 | 47,084 | ||||||||||||
Depreciation, amortization and accretion | 10,299 | 153 | 774 | 11,226 | ||||||||||||
Direct general and administrative expense | 1,930 | — | 544 | 2,474 | ||||||||||||
Other, net | 2,554 | — | 284 | 2,838 | ||||||||||||
Segment operating income (loss) | 29,211 | (110 | ) | 5,541 | 34,642 | |||||||||||
Equity earnings | 21,194 | 13,621 | — | 34,815 | ||||||||||||
Segment profit | $ | 50,405 | $ | 13,511 | $ | 5,541 | $ | 69,457 | ||||||||
Reconciliation to the Consolidated Statements of Income: | ||||||||||||||||
Segment operating income | $ | 34,642 | ||||||||||||||
General and administrative expenses: | ||||||||||||||||
Allocated-affiliate | (7,662 | ) | ||||||||||||||
Third party-direct | (668 | ) | ||||||||||||||
Combined operating income | $ | 26,312 | ||||||||||||||
Three Months Ended March 31, 2007: | ||||||||||||||||
Segment revenues | $ | 120,428 | $ | 561 | $ | 12,826 | $ | 133,815 | ||||||||
Product cost and shrink replacement | 39,675 | — | 2,520 | 42,195 | ||||||||||||
Operating and maintenance expense | 33,097 | 550 | 8,866 | 42,513 | ||||||||||||
Depreciation, amortization and accretion | 12,175 | 304 | 699 | 13,178 | ||||||||||||
Direct general and administrative expense | 1,821 | — | 498 | 2,319 | ||||||||||||
Other, net | 2,384 | — | 190 | 2,574 | ||||||||||||
Segment operating income (loss) | 31,276 | (293 | ) | 53 | 31,036 | |||||||||||
Equity earnings | 11,328 | 3,931 | — | 15,259 | ||||||||||||
Segment profit | $ | 42,604 | $ | 3,638 | $ | 53 | $ | 46,295 | ||||||||
Reconciliation to the Consolidated Statements of Income: | ||||||||||||||||
Segment operating income | $ | 31,036 | ||||||||||||||
General and administrative expenses: | ||||||||||||||||
Allocated-affiliate | (7,224 | ) | ||||||||||||||
Third party-direct | (527 | ) | ||||||||||||||
Combined operating income | $ | 23,285 | ||||||||||||||
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Item 2. 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 included in Item 1 of Part I of this quarterly 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 Four Corners and 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 limited liability company membership interests (together, the Wamsutter Ownership Interests). We account for the Wamsutter Ownership Interests as an equity investment. | ||
• | Gathering and Processing — Gulf.Our Gulf segment includes (1) our 60% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. We account for our ownership interest in Discovery as an equity investment. | ||
• | NGL Services.Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas. |
Executive Summary
Our results for the first quarter of 2008 reflect record per-unit commodity margins at Four Corners, which more than offset the negative impacts of severe winter weather, continued downtime related to the November 2007 fire at the Ignacio plant and increased system losses. The severe weather reduced gathered volumes and limited our ability to connect new wells during much of the first quarter. Our two equity method investments, Wamsutter and Discovery, also generated improved results over the prior year. Wamsutter also faced severe winter weather challenges, but distributed $22.7 million in cash distributions during the first full quarter following the acquisition of our ownership interests. Discovery was able to significantly increase its quarterly cash distribution to a record $16.8 million. Based on this combined performance, we continued our record of consecutive unitholder distribution increases since our initial public offering (IPO) with our first-quarter 2008 distribution of $0.60 per unit, which is 20% higher than the first-quarter 2007 distribution.
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Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2008, compared to the three months ended March 31, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All information in the following discussion and analysis of results of operations has been recast to reflect the combined historical results of our investments in Discovery and Wamsutter throughout the periods presented following our acquisition of the additional 20% interest in Discovery and the Wamsutter Ownership Interests in June and December 2007, respectively.
Three months ended | ||||||||||||
March 31, | % Change from | |||||||||||
2008 | 2007 | 2007(1) | ||||||||||
(Thousands) | ||||||||||||
Revenues | $ | 150,362 | $ | 133,815 | +12 | % | ||||||
Costs and expenses: | ||||||||||||
Product cost and shrink replacement | 52,098 | 42,195 | -23 | % | ||||||||
Operating and maintenance expense | 47,084 | 42,513 | -11 | % | ||||||||
Depreciation, amortization and accretion | 11,226 | 13,178 | +15 | % | ||||||||
General and administrative expense | 10,804 | 10,070 | -7 | % | ||||||||
Taxes other than income | 2,505 | 2,114 | -18 | % | ||||||||
Other expense | 333 | 460 | +28 | % | ||||||||
Total costs and expenses | 124,050 | 110,530 | -12 | % | ||||||||
Operating income | 26,312 | 23,285 | +13 | % | ||||||||
Equity earnings — Wamsutter | 21,194 | 11,328 | +87 | % | ||||||||
Equity earnings — Discovery | 13,621 | 3,931 | NM | |||||||||
Interest expense | (17,736 | ) | (14,390 | ) | -23 | % | ||||||
Interest income | 238 | 983 | -76 | % | ||||||||
Net income | $ | 43,629 | $ | 25,137 | +74 | % | ||||||
(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. |
Three months ended March 31, 2008 vs. three months ended March 31, 2007
Revenues increased $16.5 million, or 12%, due primarily to higher revenues in our Gathering and Processing — West segment and our NGL Services segment. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales resulting from significantly higher average NGL sales prices and higher sales of NGLs on behalf of third party producers, partially offset by lower NGL sales volumes and lower gathering and processing volumes. Revenues in our NGL Services segment increased due primarily to higher product sales, fractionation and storage revenues. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.
Product cost and shrink replacement increased $9.9 million, or 23%, due primarily to increases in both our Gathering and Processing — West segment and our NGL Services segment. Product cost and shrink replacement in our Gathering and Processing — West segment increased due primarily to increased purchases of NGLs from third party producers who elected to have us sell their NGLs and higher average natural gas prices, partially offset by lower shrink requirements due to lower processing volumes. Product cost and shrink replacement in our NGL Services segment increased due primarily to the higher sales volumes. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.
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Operating and maintenance expense increased $4.6 million, or 11%, due primarily to higher system losses and revaluation of product imbalances in our Gathering and Processing — West segment, partially offset by a favorable change in gains and losses on product imbalances 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.
The $2.0 million, or 15%, decrease in Depreciation, amortization and accretion reflects $2.0 million of first-quarter 2007 adjustments in our Gathering and Processing — West segment. This fluctuation is discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.
Operating income increased $3.0 million, or 13%, due primarily to higher per-unit NGL sales margins in our Gathering and Processing — West segment and increased fractionation and storage revenues and lower operating and maintenance costs in our NGL Services segment. These increases were substantially offset by higher operating and maintenance expense and lower fee-based gathering and processing revenue in our Gathering and Processing — West segment.
Equity earnings from Wamsutter increased $9.9 million, or 87%, due primarily to higher per-unit NGL sales margins on higher NGL sales volumes and is discussed in detail in the “— Results of Operations — Gathering and Processing — West” section. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements, for a discussion of how Wamsutter allocates its net income between its member owners including us.
Equity earnings from Discovery increased $9.7 million, also due primarily to higher per-unit NGL sales margins on higher NGL sales volumes. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.
Interest expense increased $3.3 million, or 23%, due to interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of Wamsutter Ownership Interests.
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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 Wamsutter Ownership Interests.
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Thousands) | ||||||||
Revenues | $ | 132,333 | $ | 120,428 | ||||
Costs and expenses, including interest: | ||||||||
Product cost and shrink replacement | 47,446 | 39,675 | ||||||
Operating and maintenance expense | 40,893 | 33,097 | ||||||
Depreciation, amortization and accretion | 10,299 | 12,175 | ||||||
General and administrative expense — direct | 1,930 | 1,821 | ||||||
Taxes other than income | 2,221 | 1,924 | ||||||
Other expense, net | 333 | 460 | ||||||
Total costs and expenses, including interest | 103,122 | 89,152 | ||||||
Segment operating income | 29,211 | 31,276 | ||||||
Equity earnings — Wamsutter | 21,194 | 11,328 | ||||||
Segment profit | $ | 50,405 | $ | 42,604 | ||||
Four Corners
Three months ended March 31, 2008 vs. three months ended March 31, 2007
Revenues increased $11.9 million, or 10% percent, due primarily to $17.6 million higher product sales partially offset by $5.6 million lower gathering and processing revenue.
Product sales revenues increased due primarily to:
• | $16.6 million related to a 59% increase in average NGL sales prices realized on sales of NGLs which we received under keep-whole and percent-of-liquids processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods; | ||
• | $7.5 million higher 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 increase is offset by higher associated product costs of $7.5 million discussed below; and | ||
• | $1.0 million higher condensate and LNG sales. |
These product sales increases were partially offset by $7.6 million lower revenues related to a 21% decrease in NGL volumes that Four Corners received under keep-whole and percent-of-liquids processing contracts. The decreased NGL volumes were due primarily to lower processing volumes caused by prolonged, severe winter weather during January and February of 2008 and the impact of the fire at the Ignacio gas processing plant in November 2007. The plant was shut down until January 18, 2008.
Fee-based gathering and processing revenues decreased $5.6 million, or 9%, due primarily to $4.8 million lower revenue from an 8% decrease in gathered and processed volumes and an $0.8 million decrease from 2007 billings of back charges on a customer contract for 2005 and 2006. The decreased gathered and processed volumes were also caused by the weather and fire-related impacts discussed previously.
Product cost and shrink replacement increased $7.8 million, or 20%, due primarily to:
• | $7.5 million increase from third party producers who elected to have us purchase their NGLs, which was |
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offset by the corresponding increase in product sales discussed above; and |
• | $3.3 million increase from 22% higher average natural gas prices. |
These increases were partially offset by a $2.4 million decrease from 14% lower volumetric shrink requirements associated with the decreased NGL volumes received under Four Corners’ keep-whole processing contracts discussed above.
Operating and maintenance expense increased $7.8 million, or 24%, due primarily to $7.1 million higher non-shrink natural gas purchases caused primarily by $5.0 million higher system losses. During the first quarter of 2008 our volumetric loss, as a percentage of total volume received, was higher than in 2007. While our system losses are generally an unpredictable component of our operating costs, they can be higher during periods of prolonged, severe winter weather, such as those we experienced during January and February of 2008. Additionally, operational inefficiencies caused by the fire at the Ignacio plant impacted our system losses. In 2008 we also had $2.5 million of higher expense related to the revaluation of product imbalances with our producer customers and gathering fuel expense. Product imbalance revaluations fluctuate with changes in the underlying price of natural gas and with changes in imbalance levels. Gathering fuel expense was unfavorably impacted by the weather and operational inefficiencies caused by the fire at the Ignacio gas processing plant previously mentioned.
The $1.9 million, or 15%, decrease in depreciation, amortization and accretion expense is due primarily to the $2.0 million of first-quarter 2007 right-of-way amortization and asset retirement obligations corrections.
Segment operating income decreased $2.1 million, or 7%, due primarily to $7.8 million higher operating and maintenance expense and $5.6 million lower fee-based gathering and processing revenue. These were substantially offset by $9.8 million higher product sales margins resulting primarily from sharply increased per-unit margins on lower NGL sales volumes and $1.9 million lower depreciation, amortization and accretion expense.
Outlook
• | We anticipated that growth capital investments we completed in 2007 to support ConocoPhillips’ and other producer customers’ drilling activity, expansion opportunities and production enhancement activities would be sufficient to offset the historical decline and slightly increase 2008 average gathering and processing volumes above 2007 levels. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both our and our customers’ ability to access facilities and maintain production. We currently expect average gathering and processing volumes in the second through fourth quarters of 2008 will be slightly higher as compared with the same quarters of 2007 although full-year 2008 gathering and processing volumes will be slightly lower as compared to 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 combined with the hedging program 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. | ||
• | Throughout the remainder of 2008, we may experience periodic restrictions in the volume of NGLs we can deliver to third-party pipelines. These restrictions happen for a variety of reasons including a lack of capacity. If alternative delivery options are unavailable, such restrictions could impact our ability to recover and sell NGLs, which might otherwise have been available from our Four Corners processing plants. | ||
• | We currently have financial swap contracts to hedge 5.4 million gallons of our monthly forecasted NGL sales and fixed price natural gas purchase contracts to hedge the price of our natural gas shrink replacement associated with these NGL sales for April through December 2008. The 5.4 million gallons per month represents approximately 40% of our 2007 NGL sales for these same months. On an aggregate basis, as of March 31, 2008, there remains a hedged margin of $25.0 million or an average of $0.51 per gallon on these NGL sales in 2008. The primary purpose of these hedges is to mitigate risk associated with ethane sales derived from keep- |
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whole processing arrangements. Of the 5.4 million gallons, 4.2 million are ethane sales. The average hedged margin on these forecasted keep-whole NGL sales exceeds the average margin realized on keep-whole NGL sales for 2007. | |||
• | We anticipate that operating costs, excluding compression, gathering fuel 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 August 31, 2008, and are negotiating with the JAN to sell them these gathering assets. The current special business license requires the execution of a purchase and sale agreement for these gathering assets on or before May 31. It is anticipated that this sale will be completed during the third or fourth quarter of 2008. As a result of the maturation of negotiations during the first quarter of 2008, these assets have been classified as held for sale on the consolidated balance sheet and include property, plant and equipment. Current expectations are that the final terms of the sale will allow us to maintain partial revenues associated with gathering and processing services for gas produced from the JAN lands and continued operations of the gathering assets on the JAN lands through at least 2009. We believe the expected proceeds from the sale of these assets will substantially exceed their carrying value. 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 to $30 million of Four Corners’ annual gathering and processing revenue less related product costs. |
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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. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements for a discussion of how Wamsutter allocates its net income between its member owners including us.
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Thousands) | ||||||||
Revenues | $ | 67,625 | $ | 40,173 | ||||
Costs and expenses, including interest: | ||||||||
Product cost and shrink replacement | 26,030 | 14,298 | ||||||
Operating and maintenance expense | 11,637 | 7,047 | ||||||
Depreciation and accretion | 5,228 | 4,258 | ||||||
General and administrative expense | 3,219 | 2,820 | ||||||
Taxes other than income | 484 | 422 | ||||||
Other income, net | (167 | ) | — | |||||
Total costs and expenses | 46,431 | 28,845 | ||||||
Net income | $ | 21,194 | $ | 11,328 | ||||
Williams Partners’ interest – equity earnings per our Consolidated Statements of Income | $ | 21,194 | $ | 11,328 | ||||
Three months ended March 31, 2008 vs. three months ended March 31, 2007
Revenues increased $27.5 million, or 68%, due primarily to $28.7 million higher product sales slightly offset by $0.9 million lower gathering and processing revenue.
Product sales revenues increased $28.7 million, or 138%, due primarily to:
• | $16.2 million related to a 54% increase in average NGL sales prices realized on sales of NGLs which Wamsutter received under keep-whole processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods. |
• | $9.4 million related to a 45% increase in NGL volumes that Wamsutter received under keep-whole processing contracts. Severe winter weather conditions in 2008 lowered volumes received under some of Wamsutter’s larger fee-based processing agreements. This allowed Wamsutter to process greater volumes under keep-whole processing arrangements. |
• | $3.1 million related to favorable adjustments to the margin sharing provisions of one of Wamsutter’s significant contracts. |
These product sales increases were partially offset by $1.0 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 NGLs from the third party producers and sells them to an affiliate. This decrease is offset by lower associated product costs of $1.0 million discussed below.
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Gathering and processing revenues decreased $0.9 million, or 5%, due primarily to $2.3 million related to a 15% decrease in the average volumes, partially offset by $1.5 million related to an 11% increase in the average fee received for these services. The decrease in average volumes was due primarily to production problems caused by severe winter weather conditions. 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.
Product cost and shrink replacement increased $11.7 million, or 82%, due primarily to:
• | $6.8 million increase from 36% higher average natural gas prices; and |
• | $5.9 million increase from 45% higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts; |
These increases were partially offset by $1.0 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 $4.6 million, or 65%, due primarily to $3.7 million higher gathering fuel costs caused by higher average natural gas prices and weather related operational problems.
Depreciation and accretion expense increased $1.0 million, or 23%, due primarily to new assets placed into service.
Net income increased $9.9 million, or 87%, due primarily to $14.0 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes and $3.1 million higher product sales resulting from charges recovered on one of Wamsutter’s contracts. Partially offsetting these increases were $4.6 million higher operating and maintenance expenses, $1.2 million lower fee-based gathering and processing revenues and $1.0 million higher depreciation and accretion expense.
Outlook
• | Compared to 2007, Wamsutter anticipated that sustained drilling activity, expansion opportunities and production enhancement activities by producers would have been sufficient to offset the historical production decline and to increase Wamsutter’s average gathering volumes. However, first-quarter 2008 volumes were significantly impacted by severe weather conditions that inhibited both Wamsutter’s and their customers’ ability to access facilities and maintain production, resulting in lower than expected volumes. We currently expect average gathering and processing volumes in the second through fourth quarters of 2008 will be slightly higher as compared with these same quarters of 2007 and that full-year 2008 gathering and processing volumes will be flat as compared to 2007. |
• | 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 resulting in gas being bypassed around the Echo Springs plant. Under normal operating conditions, this results in lower NGL volumes received under keep-whole processing contracts. In 2008, we anticipate that an agreement providing us with third party propanes, butanes and natural gasoline processing for Wamsutter bypassed gas at Colorado Interstate Gas Company’s (CIG) Rawlins natural gas processing plant will increase the processing capacity available to Wamsutter by 80 million cubic feet per day (MMcf/d) or approximately 20%. We anticipate that this third party processing will result in an increase in NGL volumes sold by Wamsutter. Due to operational problems caused by severe winter weather in the first quarter of 2008, processing volumes have not been sufficient to fully utilize Echo Springs’ plant capacity; therefore, minimal volumes have been processed by CIG. We do anticipate the volumes to increase for the remainder of the year allowing us to realize increased NGL volumes through the third-party processing agreement. |
• | 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. Natural gas prices have returned to more comparable levels in 2008 and we |
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do not expect them to return to 2007 levels. 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. |
• | Throughout the remainder of 2008, we may experience periodic restrictions in the volume of NGLs we can deliver to third-party pipelines. These restrictions happen for a variety of reasons including a lack of capacity. If alternative delivery options are unavailable, such restrictions could impact our ability to recover and sell NGLs, which might otherwise have been available from our Echo Springs processing plant. |
• | Operating costs, excluding system gains and losses and new third-party processing fees at the CIG’s Rawlins plant, are expected to approximate those in 2007. System gains and losses are an unpredictable component of our operating costs. Additionally, the new third-party processing arrangement at CIG’s Rawlins plant mentioned above requires that we pay a fee per million British thermal units (MMbtu) processed that will add approximately $4.0 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.
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Thousands) | ||||||||
Segment revenues | $ | 567 | $ | 561 | ||||
Costs and expenses: | ||||||||
Operating and maintenance expense | 524 | 550 | ||||||
Depreciation | 153 | 304 | ||||||
Total costs and expenses | 677 | 854 | ||||||
Segment operating loss | (110 | ) | (293 | ) | ||||
Equity earnings — Discovery | 13,621 | 3,931 | ||||||
Segment profit | $ | 13,511 | $ | 3,638 | ||||
Carbonate Trend
Segment operating loss decreased $0.2 million, or 62%, due primarily to lower depreciation following the property impairment recognized in the fourth quarter of 2007.
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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.
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Thousands) | ||||||||
Revenues | $ | 87,156 | $ | 52,481 | ||||
Costs and expenses, including interest: | ||||||||
Product cost and shrink replacement | 52,240 | 33,518 | ||||||
Operating and maintenance expense | 7,008 | 6,415 | ||||||
Depreciation and accretion | 6,983 | 6,483 | ||||||
General and administrative expense | 1,750 | 544 | ||||||
Interest income | (264 | ) | (661 | ) | ||||
Other income, net | (3,262 | ) | (369 | ) | ||||
Total costs and expenses, including interest | 64,455 | 45,930 | ||||||
Net income | $ | 22,701 | $ | 6,551 | ||||
Williams Partners’ 60 percent interest – Equity earnings per our Consolidated Statements of Income | $ | 13,621 | $ | 3,931 | ||||
Three months ended March 31, 2008 vs. three months ended March 31, 2007
Revenues increased $34.7 million, or 66%, due primarily to $33.6 million higher product sales resulting from:
• | $20.3 million from 105% higher NGL volumes due primarily to an increase in volumes processed under keep-whole processing arrangements; | ||
• | $11.7 million related to a 29% increase in average NGL sales prices realized on sales of NGLs which Discovery received under certain processing contracts. This increase resulted from general increases in market prices for these commodities between the two periods; and | ||
• | $3.7 million higher sales of NGLs on behalf of third party producers for whom Discovery purchases their NGLs for a fee under their contracts. This increase is offset by higher associated product costs of $3.7 million discussed below. |
These increases were partially offset by $2.0 million lower sales of excess fuel and shrink replacement gas. The lower sales on excess fuel and shrink replacement gas is offset by lower excess shrinkage cost and is described below.
Product cost and shrink replacement increased $18.7 million, or 56%, due primarily to:
• | $12.3 million higher volumetric natural gas requirements from increased keep-whole processing activity; | ||
• | $3.7 million higher product purchase cost for the processing customers who elected to have Discovery purchase their NGLs; | ||
• | $2.6 million increase in payments for gas processing rights from third-party processors; and |
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• | $2.4 million increase from higher average natural gas prices. |
These increases were partially offset by a $2.0 million decrease in cost associated with the sales of excess fuel and shrink replacement gas mentioned above.
General and administrative expense increased $1.2 million due primarily to a proposed increase in Discovery’s management fee charged by Williams. The management fee is in the process of being re-negotiated effective January 1, 2008 as discussed below.
Other income, net increased $2.9 million due primarily to $3.5 million from the reversal of amounts previously reserved from 1998 through 2003 for system fuel and lost and unaccounted for gas in connection with the recently approved FERC settlement filing.
Net income increased $16.2 million due primarily to $14.9 million higher product sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes and $2.9 million for higher other income, net, partially offset by $1.2 million higher general and administrative expense.
Outlook
Discovery
Throughput volumes on Discovery’s pipeline system are an important component of maximizing its profitability. Pipeline throughput volumes from existing wells connected to its 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 plant and fractionator, Discovery must continually obtain new supplies of natural gas.
• | 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. | ||
• | Discovery’s Tahiti pipeline lateral was installed on the sea bed in February 2007. Chevron has recently moved the production facility to location indicating their ongoing progress toward first production. Chevron 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. | ||
• | The Texas Eastern Transmission Company (TETCO) agreement was recently extended through May 2008 after which time we expect no further volumes under this agreement. Current flowing volumes are approximately 170 billion British thermal units per day (BBtu/d). | ||
• | Gross processing margins have been at record high levels due to commodity prices for NGLs and natural gas, 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. |
• | Discovery’s Larose gas processing plant has been operating at near capacity. We expect that additional processing volumes from the Tennessee Gas Pipeline (TGP) system in 2008 will 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. |
• | Discovery receives a significant amount of the processing volumes from TGP via a very large third-party owned natural gas platform. The platform was recently shut down after a leak was discovered on a |
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pipeline near the platform. Processing volumes received from TGP will be impacted during the ongoing shut down while repairs are being made and could reduce Discovery’s 2008 operating profit by approximately $4.0 million to $5.0 million. | |||
• | 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. At this time, Discovery began receiving minimum payments of approximately $0.2 million per month under this agreement and expects an increase when production begins in early summer 2008. | ||
• | We expect Discovery’s 2008 results will be favorably impacted by approximately $3.0 million due to its recently approved FERC rate filing pertaining to the regulated portion of its business. | ||
• | Discovery has recently received an additional dedication in four blocks for an estimated 60 trillion British thermal units of new natural gas reserves with ATP Oil and Gas Corporation (ATP) around its Gomez facility. Discovery also recently contracted three blocks in the Mirage, Morgas and Telemark areas with capital requirements to connect to Discovery’s facilities to be funded entirely by ATP. | ||
• | Discovery is currently renegotiating the management fee it is charged by Williams for providing senior management guidance, legal, marketing, financial analysis, information technology, accounting and other management services to Discovery. Discovery expects an increase of approximately $1.0 million per quarter and the increase has been recognized as part of Discovery’s first-quarter results. |
Results of Operations – NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50 percent interest in the Conway fractionator.
Three months ended | ||||||||
March 31, | ||||||||
2008 | 2007 | |||||||
(Thousands) | ||||||||
Segment revenues | $ | 17,462 | $ | 12,826 | ||||
Costs and expenses: | ||||||||
Product cost | 4,652 | 2,520 | ||||||
Operating and maintenance expense | 5,667 | 8,866 | ||||||
Depreciation and accretion | 774 | 699 | ||||||
General and administrative expense — direct | 544 | 498 | ||||||
Other expense, net | 284 | 190 | ||||||
Total costs and expenses | 11,921 | 12,773 | ||||||
Segment profit | $ | 5,541 | $ | 53 | ||||
Three months ended March 31, 2008 vs. three months ended March 31, 2007
Segment revenues increased $4.6 million, or 36%, due primarily to higher product sales, fractionation and storage revenues. The significant components of the revenue fluctuations are addressed more fully below.
• | Product sales increased $1.9 million due to higher sales volumes of ethane and normal butane. The increase in sales volumes was more than offset by the related increase in product cost discussed below. |
• | Fractionation revenues increased $1.4 million due primarily to the expiration of a fractionation contract with a cap on the per-unit fee, which limited our ability to pass through increases in fractionation fuel expense to this customer. |
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• | Storage revenues increased $0.9 million due primarily to higher average storage revenues from additional storage leases. |
Product cost increased $2.1 million, or 85%, due to the higher product sales volumes discussed above. This resulted in a net margin loss of $0.2 million.
Operating and maintenance expense decreased $3.2 million, or 36%, due primarily to a $1.4 million first- quarter 2007 product imbalance valuation adjustment and a $1.4 million improvement in gains and losses on storage and fractionation product imbalances.
Segment profit increased $5.5 million due primarily to higher fractionation and storage revenues and lower operating and maintenance costs.
Outlook
• | We expect 2008 storage revenues will be 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 for 2008 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; | ||
• | Proceeds from the sale of gathering assets to the Jicarilla Apache Nation; | ||
• | Capital contributions from Williams pursuant to the omnibus agreement; and | ||
• | Credit facilities, as needed. |
We anticipate our more significant uses of cash for the remainder of 2008 to be:
• | Maintenance and expansion capital expenditures for our Four Corners and Conway assets; | ||
• | Contributions we must make to Wamsutter LLC to fund certain of its expansion capital expenditures; | ||
• | Completion of the Four Corners repair expenditures related to the fire at Ignacio gas processing plant, which generally should be reimbursed by insurance approximately as they are incurred; | ||
• | Interest on our long-term debt; and | ||
• | Quarterly distributions to our unitholders. |
Wamsutter Distributions
Wamsutter expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Wamsutter made the following 2008 distributions to its members (all amounts in thousands):
Total Distribution to | ||||||||
Date of Distribution | Members | Our Share | ||||||
3/28/08 | $25,000 | $21,438 |
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Wamsutter’s distribution in March included a payment of approximately $7.1 million to the Class C membership interests, which are currently 50% owned by us and 50% owned by Williams. However, the Wamsutter LLC agreement provides that to the extent at the end of the fourth quarter of a distribution year, the Class A member has received less than $70.0 million, the Class C members will be required to repay any distributions received in that distribution year such that the Class A member receives $70.0 million for that distribution year. Thus, our Class A membership interest will ultimately receive the first $70.0 million of cash for any distribution year. Additionally, during the first quarter of 2008 Williams paid Wamsutter and Wamsutter paid us $1.3 million in transition support payments related to the amount by which Wamsutter’s general and administrative expenses exceeded a certain cap.
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 2008 distributions to its members (all amounts in thousands):
Total Distribution to | ||||||||
Date of Distribution | Members | Our 60% Share | ||||||
1/30/08 | $28,000 | $16,800 | ||||||
4/30/08 | $26,000 | $15,600 |
Insurance Recoveries
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 $29.0 million, including $28.0 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $15.0 million has been incurred through March 31, 2008. We are funding these repairs with cash flows from operations, are seeking reimbursement from our insurance carrier, and have received $12.0 million of insurance proceeds to date. Additionally, we will seek reimbursement from our insurance carrier for lost profits under our business interruption policy.
Sale of Gathering Assets to the Jicarilla Apache Nation
As previously discussed, we may receive a significant amount of proceeds from the sale of our gathering assets on the JAN lands in either the third or fourth quarter of 2008. Cash proceeds resulting from this capital transaction will not be considered in the determination of the amount of subsequent quarterly distributions of available cash to our unitholders. We expect to reinvest these cash proceeds in internal projects and/or acquisition transactions in part to offset the loss of future earnings and cash flows associated with these assets.
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 March 31, 2008, we have received $5.7 million from Williams for indemnified items since inception of the agreement in August 2005. Thus, approximately $8.3 million remains available for reimbursement of our costs on these items. |
• | Additionally, under the omnibus agreement, we will receive (1) an annual credit for general and administrative expenses of $1.6 million in 2008 and $0.8 million in 2009 and (2) 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 March 31, 2008 we have received $1.6 million from Williams for the Tahiti-related indemnification since inception. |
Although in 2007 we 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
We have a $200.0 million revolving credit facility with Citibank, N.A. as administrative agent available for
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borrowings and letters of credit. 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 five years. There were no amounts outstanding at March 31, 2008 under the revolving credit 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 March 31, 2008 we had no outstanding borrowings under the working capital credit facility.
Wamsutter has a $20.0 million revolving credit facility with Williams as the lender. The credit facility is available exclusively to fund working capital requirements. Wamsutter is 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 March 31, 2008, Wamsutter had no outstanding borrowings under the working capital credit facility.
Capital Requirements
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 requirements 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. |
The following table provides summary information related to our, Wamsutter’s and Discovery’s expected capital expenditures for 2008 and actual spending through March 31, 2008 (in millions):
Maintenance | Expansion | Total | ||||||||||||||||||||||
Through | Through | Through | ||||||||||||||||||||||
Company | Total Year Estimate | Mar. 31, 2008 | Total Year Estimate | Mar. 31, 2008 | Total Year Estimate | Mar. 31, 2008 | ||||||||||||||||||
Four Corners | $ | 23.0 | $ | 8.5 | $ | 14.5 | $ | 1.5 | $ | 37.5 | $ | 10.0 | ||||||||||||
Conway | 3.2 | .6 | 13.9 | 1.0 | 17.1 | 1.6 | ||||||||||||||||||
Wamsutter – (our share) | 20.0 | 3.3 | 5.2 | .4 | 25.2 | 3.7 | ||||||||||||||||||
Discovery — (our share) | 3.6 | .1 | 9.0 | 1.4 | 12.6 | 1.5 |
We expect to fund Four Corners’ and Conway’s maintenance and expansion capital expenditures with cash flows from operations. For 2008, Four Corners’ estimate of 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’ 2008 expansion capital expenditures relate primarily to plant and gathering system expansion projects. Conway’s 2008 expansion capital expenditures relate to various small projects.
Wamsutter’s 2008 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
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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 2008 maintenance and expansion capital expenditures either by cash calls to its members or from its cash flows from operations.
Cash Distributions to Unitholders
We paid quarterly distributions to common and subordinated unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recent quarterly distribution of $37.9 million will be paid on May 15, 2008 to the general partner interest and common unitholders of record at the close of business on May 7, 2008. This distribution includes an additional incentive distribution to our general partner of approximately $5.5 million.
Results of Operations — Cash Flows
Three months ended | ||||||||
March 31, | ||||||||
Williams Partners L.P. | 2008 | 2007 | ||||||
(Thousands) | ||||||||
Net cash provided by operating activities | $ | 41,522 | $ | 49,816 | ||||
Net cash used by investing activities | (8,728 | ) | (10,216 | ) | ||||
Net cash used by financing activities | (34,436 | ) | (18,649 | ) |
Net cash provided by operating activities decreased $8.3 million for the first three months of 2008 as compared to 2007 due primarily to:
• | $16.6 million decrease in cash provided by working capital excluding accrued interest. Cash provided by working capital decreased due primarily to changes in our accounts receivable between the two periods; and | ||
• | $24.4 million higher cash interest payments for the interest on our $750.0 million senior unsecured notes issued in June and December 2006 to finance our acquisition of Four Corners and on our $250.0 million term loan issued in December 2007 to finance our acquisition of Wamsutter. |
Partially offsetting these decreases were $33.7 million higher distributions from Wamsutter and Discovery.
Net cash used by financing activities increased $15.8 million for the first quarter of 2008 as compared to the first quarter of 2007 due to an increase in quarterly distributions to unitholders and our general partner.
Three months ended | ||||||||
March 31, | ||||||||
Wamsutter — 100 percent | 2008 | 2007 | ||||||
(Thousands) | ||||||||
Net cash provided by operating activities | $ | 28,625 | $ | 15,619 | ||||
Net cash used by investing activities | (4,089 | ) | (13,581 | ) | ||||
Net cash used by financing activities | (24,536 | ) | (2,038 | ) |
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The $13.0 million increase in net cash provided by operating activities in the first quarter of 2008 as compared to the first quarter of 2007 is due primarily to $10.8 million increase in operating income, as adjusted for non-cash expenses.
Net cash used by investing activities in the first quarter of 2008 and 2007 is primarily comprised of capital expenditures related to the connection of new wells. Severe winter weather during the first quarter of 2008 reduced the ability to connect new wells.
Net cash used by financing activities in the first quarter of 2008 is almost entirely related to cash distributions to Wamsutter’s members pursuant to the distribution provisions of Wamsutter’s limited liability company agreement. Net cash used by financing activities in the first quarter of 2007 is primarily distributions of Wamsutter’s net cash flows to Williams pursuant to its participation in Williams’ cash management program.
Three months ended | ||||||||
March 31, | ||||||||
Discovery — 100 percent | 2008 | 2007 | ||||||
(Thousands) | ||||||||
Net cash provided by operating activities | $ | 32,043 | $ | 1,001 | ||||
Net cash used by investing activities | (3,882 | ) | (1,050 | ) | ||||
Net cash used by financing activities | (25,672 | ) | (6,600 | ) |
The $31.0 million increase in net cash provided by operating activities in the first quarter of 2008 as compared to the first quarter of 2007 is due primarily to $17.5 million increase in operating income, as adjusted for non-cash expenses, and an increase of $13.9 million in working capital.
The $19.1 million increase in net cash used by financing activities in the first quarter of 2008 as compared to the first quarter of 2007 is due primarily to increased distributions to members.
Fair Value Measurements
On January 1, 2008 we adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements”, for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy commodity derivatives. See Note 8 of Notes to Consolidated Financial Statements for disclosures regarding SFAS No. 157, including discussion of the fair value hierarchy levels and valuation methodologies.
At March 31, 2008, our energy derivative assets and liabilities are valued using unobservable inputs and included in Level 3. They consist of financial swap contracts that hedge future sales of NGL volumes that our Four Corners operation receives as compensation under certain processing agreements. The model used to value these financial swap contracts applies an internally developed forecast of future NGL prices at Four Corners. The forward NGL yield curve used in our pricing model is an unobservable input as comparable market data is not available. The change in the overall fair value of these transactions included in Level 3 results primarily from changes in NGL prices. The financial swap contracts are designated as cash flow hedges. As such, net unrealized gains and losses from changes in fair value are recorded in other comprehensive income and subsequently impact earnings when the underlying hedged NGLs are sold.
Item 3. Quantitative and Qualitative 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.
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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 $0.8 million at March 31, 2008, and $1.0 million at December 31, 2007.
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 interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first three months of 2008. See Note 6 of Notes to Consolidated Financial Statements.
Item 4. 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 — (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 or our internal controls over financial reporting (Internal 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
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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 Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.
Changes in Internal Control Over Financial Reporting
There have been no changes during the first quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
The information required for this item is provided in Note 9, Commitments and Contingencies, included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which information is incorporated by reference into this item.
Item 1A. Risk Factors
Part I., Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December 31, 2007, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed except as set forth below:
Our future financial and operating flexibility may be adversely affected by restrictions in our debt agreements 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 March 31, 2008 was $1.0 billion, representing approximately 85% 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:
• | make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes; | ||
• | impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes; | ||
• | adversely affect our ability to pay cash distributions to unitholders; | ||
• | diminish our ability to withstand a downturn in our business or the economy generally; | ||
• | require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes; limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and | ||
• | place us at a competitive disadvantage compared to our competitors that have proportionately less debt. |
Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance existing debt obligations will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
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.
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:
• | 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; | ||
• | control costs associated with acquisitions, joint ventures or construction projects; | ||
• | consummate acquisitions or joint ventures and complete construction projects; | ||
• | integrate any acquired or constructed business or assets successfully with our existing operations and into our operating and financial systems and controls; | ||
• | hire, train and retain qualified personnel to manage and operate our growing business; and | ||
• | 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 may require substantial new capital and 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. 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. Further, any limitations on our access to capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES
(d) | ||||||||||||||||
(c) | Maximum Number | |||||||||||||||
Total Number of | (or Approximate | |||||||||||||||
Units Purchased | Dollar Value) of | |||||||||||||||
(b) | as Part of | Units that May Yet | ||||||||||||||
(a) | Average | Publicly | Be Purchased | |||||||||||||
Total Number of | Price Paid | Announced Plans | Under the Plans or | |||||||||||||
Period | Units Purchased | per Unit | or Programs | Programs | ||||||||||||
January 1 – January 31, 2008 | 800,000 | (1) | $ | 36.24 | (1) | 800,000 | (1) | 0 | (1) | |||||||
February 1 – February 29, 2008 | — | — | — | — | ||||||||||||
March 1 – March 31, 2008 | — | — | — | — | ||||||||||||
Total | 800,000 | $ | 36.24 | 800,000 | 0 | |||||||||||
(1) Pursuant to an underwriting agreement, dated December 5, 2007 (the Underwriting Agreement), between us and Lehman Brothers Inc., Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representatives of the underwriters listed on schedule 1 of the Underwriting Agreement (collectively, the Underwriters), we offered and sold in a firm commitment underwritten offering 9,250,000 common units representing limited partner interests in us (the Common Units) at a price to the public of $37.75 per common unit ($36.24 per common unit, net of underwriting discounts). Pursuant to the Underwriting Agreement, we granted the Underwriters a 30-day option to purchase up to an additional 1,387,500 common units (the Option) on the same terms as the Common Units we sold. On January 9, 2008, the Underwriters purchased 800,000 additional common units from the Partnership after partially exercising the Option. Pursuant to a common unit redemption agreement, dated December 11, 2007 (the Redemption Agreement), between us and our general partner, our general partner agreed to transfer to us, and we agreed to redeem from our general partner, a number of common
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units (the Redemption Units) equal to the number of common units purchased from us by the Underwriters upon exercising the Option, in whole or in part. As a result of the partial exercise of the Option by the Underwriters, we redeemed 800,000 common units from our general partner on January 9, 2008 in accordance with the Redemption Agreement. We redeemed the Redemption Units from our general partner at a price per common unit of $36.24, the net proceeds per common unit (after underwriting discounts and commissions, but before expenses) in the public offering conducted pursuant to the Underwriting Agreement.
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Item 6. Exhibits
The exhibits listed below are filed or furnished as part of this report:
Exhibit | ||
Number | Description | |
+Exhibit 3.1 | Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3 and 4. | |
+Exhibit 31.1 | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. | |
+Exhibit 31.2 | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. | |
+Exhibit 32 | Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
+ | Filed herewith. |
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SIGNATURES
Pursuant to the requirements 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 | ||||
/s/ Ted T. Timmermans | ||||
Ted. T. Timmermans Controller (Duly Authorized Officer and Principal Accounting Officer) |
May 1, 2008
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EXHIBIT INDEX
Exhibit | ||
Number | Description | |
+Exhibit 3.1 | Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3 and 4. | |
+Exhibit 31.1 | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. | |
+Exhibit 31.2 | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. | |
+Exhibit 32 | Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
+ | Filed herewith. |
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