UNITED STATES
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 September 30, 2007March 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)
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 non-accelerated filer.smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and large accelerated filer”“smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated fileroþ                      Accelerated filerþo                      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 32,360,53852,774,728 common units and 7,000,000 subordinated units outstanding as of October 31, 2007.April 30, 2008.
 
 

 


 

WILLIAMS PARTNERS L.P.
INDEX
     
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  1819 
     
  3635 
     
  36 
     
    
     
  37 
     
  37 
     
37
  3839 
Amended and Restated Agreement
 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
 Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer
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

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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.
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

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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.
 
  Our processing, fractionation and storage businesses could be affected by any decrease in the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.
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 natural gas liquids.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 natural gas liquidsNGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
 
  Our future financialWe do not own all of the interests in Wamsutter, the Conway fractionator or Discovery, which could adversely affect our ability to operate and operating flexibility may be adversely affected by restrictionscontrol these assets in our indentures and by our leverage.a manner beneficial to us.
 
  The revolving credit facilityOur results of The Williams Companies, Inc. (“Williams”)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 interestinterests with us and limited fiduciary duties, whichand they may permit them to 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.
Unitholders may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Our operations are subject to operational hazards and unforeseen interruptions for which we may or may not be adequately insured.
     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 IA1A “Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2006.2007, 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)
                        
 Three Months Ended Nine Months Ended  Three Months Ended 
 September 30, September 30,  March 31, 
 2007 2006* 2007 2006*  2008 2007* 
Revenues:  
Product sales:  
Affiliate $75,519 $68,542 $194,190 $190,308  $78,122 $56,552 
Third-party 4,297 4,553 15,680 15,111  4,221 6,313 
Gathering and processing:  
Affiliate 9,178 10,162 27,412 30,851  8,790 9,491 
Third-party 51,721 52,679 154,246 153,460  46,210 51,103 
Storage 7,404 6,581 20,632 17,610  7,333 6,410 
Fractionation 2,723 2,708 7,256 9,650  3,292 1,917 
Other  (1,266) 1,357 3,244 3,513  2,394 2,029 
              
  
Total revenues 149,576 146,582 422,660 420,503  150,362 133,815 
  
Costs and expenses:  
Product cost and shrink replacement:  
Affiliate 18,806 19,159 59,051 58,596  22,033 21,725 
Third-party 30,043 25,542 76,670 74,824  30,065 20,470 
Operating and maintenance expense (excluding depreciation):  
Affiliate 15,275 10,681 40,087 39,768  23,133 14,328 
Third-party 25,259 26,888 77,203 76,155  23,951 28,185 
Depreciation, amortization and accretion 10,345 10,944 34,757 32,510  11,226 13,178 
General and administrative expense:  
Affiliate 10,816 7,730 29,866 24,238  9,876 9,406 
Third-party 925 1,038 2,778 3,293  928 664 
Taxes other than income 2,474 2,352 7,214 6,392  2,505 2,114 
Other (income) expense 134 90 792  (3,225)
Other expense — net 333 460 
              
  
Total costs and expenses 114,077 104,424 328,418 312,551  124,050 110,530 
              
  
Operating income 35,499 42,158 94,242 107,952  26,312 23,285 
  
Equity earnings-Wamsutter 21,194 11,328 
Equity earnings-Discovery Producer Services 7,902 6,083 15,708 15,275  13,621 3,931 
Interest expense:  
Affiliate  (16)  (15)  (46)  (45)  (25)  (15)
Third-party  (14,268)  (3,256)  (43,038)  (4,110)  (17,711)  (14,375)
Interest income 312 462 2,556 642  238 983 
              
  
Net income $29,429 $45,432 $69,422 $119,714  $43,629 $25,137 
              
  
Allocation of net income: 
Allocation of net income for calculation of earnings per unit: 
Net income $29,429 $45,432 $69,422 $119,714  $43,629 $25,137 
Allocation of net income to general partner 4,937 32,851 8,292 98,439  8,911 12,912 
              
Allocation of net income to limited partners $24,492 $12,581 $61,130 $21,275  $34,718 $12,225 
              
  
Basic and diluted net income per limited partner unit:  
Common units $0.62 $0.58 $1.41 $1.19  $0.66 $0.31 
Subordinated units 0.62 0.58 1.41 1.19  $0.66 $0.31 
  
Weighted average number of units outstanding:  
Common units 32,359,555 14,597,072 32,359,053 (a) 9,870,084  49,005,497 32,358,798 
Subordinated units 7,000,000 7,000,000 7,000,000 7,000,000  3,769,231 7,000,000 
 
* RestatedRecast as discussed in Note 1.
(a)Includes Class B units converted to Common on May 21, 2007 (See Note 8).
See accompanying notes to consolidated financial statements.

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WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
                
 September 30, December 31,  March 31, December 31, 
 2007 2006  2008 2007 
 (Unaudited)  (Unaudited) 
 (Thousands)  (In thousands) 
ASSETS
ASSETS
 
  
Current assets:  
Cash and cash equivalents $16,089 $57,541  $34,555 $36,197 
Accounts receivable:  
Trade 17,693 18,320  19,129 12,860 
Affiliate 13,757 12,420  33,036 20,402 
Other 2,908 3,991  3,852 2,543 
Gas purchase contract — affiliate 1,188 4,754 
Product imbalance 7,283 10,308  15,600 20,660 
Prepaid expense 5,187 3,765  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 2,499 2,534  3,727 3,574 
          
Total current assets 66,604 113,633  129,826 121,031 
  
Investment in Wamsutter 283,163 284,650 
Investment in Discovery Producer Services 209,791 221,187  211,783 214,526 
Property, plant and equipment, net 649,037 647,578  631,908 630,770 
Other assets 31,114 34,752 
Other noncurrent assets 30,426 32,500 
          
  
Total assets $956,546 $1,017,150  $1,287,106 $1,283,477 
          
 
LIABILITIES AND PARTNERS’ CAPITAL
LIABILITIES AND PARTNERS’ CAPITAL
 
  
Current liabilities:  
Accounts payable — trade $23,610 $19,827 
Accounts payable: 
Trade $36,208 $35,947 
Affiliate 27,329 17,676 
Product imbalance 10,774 10,959  15,578 21,473 
Deferred revenue 7,205 3,382  1,266 4,569 
Derivative liabilities — affiliate 1,521 2,718 
Accrued interest 10,563 2,796  12,043 19,500 
Other accrued liabilities 11,708 13,377  8,872 8,243 
          
Total current liabilities 63,860 50,341  102,817 110,126 
  
Long-term debt 750,000 750,000  1,000,000 1,000,000 
Environmental remediation liabilities 3,964 3,964  2,321 2,599 
Other noncurrent liabilities 8,146 3,749  9,383 9,265 
Commitments and contingent liabilities (Note 8) 
Commitments and contingent liabilities (Note 9) 
Partners’ capital 130,576 209,096  172,585 161,487 
          
  
Total liabilities and partners’ capital $956,546 $1,017,150  $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)
                
 Nine Months Ended  Three Months Ended 
 September 30,  March 31, 
 2007 2006*  2008 2007* 
 (Thousands)  (In thousands) 
OPERATING ACTIVITIES:  
Net income $69,422 $119,714  $43,629 $25,137 
Adjustments to reconcile to cash provided by operations:  
Depreciation, amortization and accretion 34,757 32,510  11,226 13,178 
Amortization of gas purchase contract — affiliate 3,566 3,998   1,188 
Gain on sale of property, plant and equipment   (2,622)
Equity earnings of Wamsutter  (21,194)  (11,328)
Equity earnings of Discovery Producer Services  (15,708)  (15,275)  (13,621)  (3,931)
Distributions related to equity earnings of Wamsutter 22,703  
Distributions related to equity earnings of Discovery Producer Services 13,106 10,183  13,621 2,620 
Cash provided (used) by changes in assets and liabilities:  
Accounts receivable 373  (25,090)  (20,212)  (1,436)
Prepaid expense  (1,500)  (1,000) 467 1,188 
Other current assets 35   5,282  (335)
Accounts payable 3,246  (8,043) 9,914 11,055 
Product imbalance 2,840  (4,900)  (835)  (183)
Accrued liabilities  (7,214) 15,460 
Deferred revenue 4,347 3,266   (3,364)  (3,012)
Accrued liabilities 10,257 3,009 
Other, including changes in non-current liabilities 4,324 771  1,120 215 
          
  
Net cash provided by operating activities 129,065 116,521  41,522 49,816 
          
  
INVESTING ACTIVITIES:  
Property, plant and equipment: 
Capital expenditures  (33,029)  (21,514)  (11,556)  (9,766)
Cumulative distributions in excess of equity earnings of Discovery Producer Services 3,179 980 
Change in accrued liabilities-capital expenditures  (4,779)   108  (1,430)
Proceeds from sales of property, plant and equipment  7,299 
Purchase of equity investment  (69,061)  (156,129)
Distributions in excess of equity earnings of Discovery Producer Services 4,964 1,817 
Other 536  
Contributions to Wamsutter  (22)  
Contributions to Discovery Producer Services  (437)  
          
  
Net cash used by investing activities  (101,369)  (168,527)  (8,728)  (10,216)
          
  
FINANCING ACTIVITIES:  
Distributions to unitholders  (35,283)  (19,491)
Proceeds from sale of common units  227,107  28,992  
Proceeds from debt issuance  150,000 
Excess purchase price over contributed basis of equity investment  (8,939)  (203,871)
Payment of debt issuance costs   (3,138)
Payment of offering costs   (2,168)
Distributions to unitholders  (62,935)  (19,875)
Distributions to The Williams Companies, Inc.   (73,842)
General partner contributions  4,841 
Redemption of common units from general partner  (28,992)  
Contributions per omnibus agreement 2,726 4,244  771 842 
Other 76  
          
  
Net cash provided (used) by financing activities  (69,148) 83,298 
Net cash used by financing activities  (34,436)  (18,649)
          
  
Increase (decrease) in cash and cash equivalents  (41,452) 31,292   (1,642) 20,951 
Cash and cash equivalents at beginning of period 57,541 6,839  36,197 57,541 
          
  
Cash and cash equivalents at end of period $16,089 $38,131  $34,555 $78,492 
          
 
* RestatedRecast 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)
                         
  Limited Partners      Accumulated Other  Total 
              General  Comprehensive  Partners’ 
  Common  Class B  Subordinated  Partner  Loss  Capital 
  (Thousands)             
Balance — January 1, 2007 $733,878  $241,923  $108,862  $(875,567)    $209,096 
Comprehensive income:                        
Net income  44,772   9,212   10,530   4,908      69,422 
Other comprehensive loss:                        
Net unrealized losses on cash flow hedges              (620)  (620)
                        
Total other comprehensive loss                      (620)
                        
Total comprehensive income                      68,802 
Cash distributions  (41,776)  (6,601)  (10,465)  (4,093)     (62,935)
Contributions pursuant to the omnibus agreement           2,726      2,726 
Conversion of B units to Common (6,805,492 units)  244,534   (244,534)            
Distribution to general partner in exchange for additional investment in Discovery           (78,000)     (78,000)
Discovery distributions to The Williams Companies, Inc., not attributable to the Partnership            (9,035)      (9,035)
Other  (78)              (78)
                   
                         
Balance — September 30, 2007 $981,330  $  $108,927  $(959,061) $(620) $130,576 
                   
                     
  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)
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 subsidiariessubsidiaries. 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”)(Discovery) in which we own a 60% interest.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 itstheir businesses and operations.
     We are a Delaware limited partnership that was formedprincipally engaged in February 2005 to acquirethe business of gathering, transporting, processing and owntreating 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) a 40% interestGathering 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 Discovery; (2)Wamsutter. Our Gathering and Processing — Gulf segment includes the Carbonate Trend gathering pipeline offand our equity investment in Discovery. Our NGL Services segment includes the coast of Alabama; (3) three integrated natural gas liquids (“NGL”) productConway fractionation and storage facilities near Conway, Kansas; and (4) a 50% undivided ownership interest in a fractionator near Conway, Kansas. Our initial public offering (the “IPO”) closed in August 2005. Williams Partners GP LLC, a Delaware limited liability company, was also formed in February 2005 to serve as our general partner. In addition, we formed Williams Partners Operating LLC (“OLLC”), an operating limited liability company (wholly owned by us), through which all our activities are conducted.
     During 2006, we acquired Williams Four Corners LLC (“Four Corners”) pursuant to two agreements with Williams Energy Services, LLC (“WES”), Williams Field Services Group LLC, Williams Field Services Company, LLC and OLLC. Because Four Corners was an affiliate of The Williams Companies, Inc. (“Williams”) at the time of the acquisition, the transactions were accounted for as a combination of entities under common control, similar to a pooling of interests, whereby the assets and liabilities of Four Corners were combined with Williams Partners L.P. at their historical amounts. Accordingly, the comparative September 30, 2006 financial statements and notes have been restated to reflect the combined results, increasing net income by $95.5 million. The restatement does not impact historical earnings per unit as pre-acquisition earnings were allocated to our general partner.operations.
     On June 28, 2007, we closed on the acquisition of an additional 20% interest in Discovery from Williams Energy, L.L.C. and WES for aggregate considerationWilliams Energy Services, LLC, bringing our total ownership of $78.0 million in cash.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 have been restated to reflect the combined historical results of our investment in DiscoveryWamsutter throughout the periods presented. We now own 60%The effect of Discovery. We continuerecasting our financial statements to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do notcommon control the investment. The acquisitionexchange increased net income $11.3 million for the nine months ended September 30, 2007 and 2006 by $2.6 million and $5.1 million, respectively. Thefirst quarter of 2007. This acquisition had nodoes not impact on earnings per unit for periods prior to the acquisition as pre-acquisition earnings were allocated to theour 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 8-K,10-K, filed August 29, 2007,February 26, 2008, for the year ended December 31, 2006.2007. 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 September 30, 2007,March 31, 2008, and results of operations for the three and nine months ended September 30,March 31, 2008 and 2007 and 2006 and cash flows for the ninethree months ended September 30, 2007March 31, 2008 and 2006.2007. 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 our Consolidated Financial Statementsthe consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
     Certain amounts have been reclassified to conform to the current classifications.

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Note 2. Recent Accounting Standards
     In February 2007,March 2008, the Financial Accounting Standards Board (“FASB”)(FASB) issued Statement of Financial Accounting Standards (“SFAS”)(SFAS) No. 159, “The Fair Value Option for Financial Assets161 “Disclosures about Derivative Instruments and Financial LiabilitiesHedging ActivitiesIncluding an Amendmentamendment of FASB Statement No. 115.133.” SFAS No. 159133, “Accounting for Derivative Instruments and Hedging Activities,currently establishes a fair value option permitting entities to elect the option to measure eligible financialdisclosure requirements for derivative instruments and certain other items athedging activities. SFAS No. 161 amends and expands the disclosure requirements of Statement 133 with

7


enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair value on specified election dates. Unrealizedvalues 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 for which the fair value option has been elected will beare reported in earnings. The fair value option may be applied onthe 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 instrument-by-instrument basis with a few exceptions, is irrevocableunderstanding of the volume and is applied only to entire instruments and not to portionspurpose of instruments.derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS No. 159161 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 asfor 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 beginningTwo-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 NovemberDecember 15, 20072008, and should notmust be retrospectively applied retrospectively to fiscal years beginning priorall periods presented. Early application is prohibited. Retrospective application of this guidance will result in a decrease in the income allocated to the effective date, except as permitted for early adoption. We will adopt SFAS No. 159 on January 1, 2008. Ongeneral partner and an increase in the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustmentincome allocated to limited partners for the initial remeasurementamount that any assumed incentive distribution exceeded the actual incentive distribution paid during that period. Certain of those items to fair value shouldour historical periods’ earnings per unit will be reportedrevised as a cumulative effect adjustment toresult of this change. Adoption of this new standard only impacts the opening balanceallocation of retained earnings. We continue to assess whether to apply the provisionsearnings for purposes of SFAS No. 159 to eligible financial instruments in place on the adoption datecalculating our earnings per limited partner unit and the relatedwill have no impact on our Consolidated Financial Statements.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, for the three months and nine months ended September 30, 2007 and 2006 is as follows (in thousands):
                        
 Three months ended Nine months ended  Three months ended 
 September 30, September 30,  March 31, 
 2007 2006* 2007 2006*  2008 2007 
  
Allocation to general partner:  
Net income $29,429 $45,432 $69,422 $119,714  $43,629 $25,137 
Net income applicable to pre-partnership operations allocated to general partner   (33,472)  (2,602)  (100,575)   (12,639)
2nd quarter beneficial conversion of Class B units**
    (5,308)  
Charges direct to general partner: 
Reimbursable general and administrative costs 605 806 1,795 2,393 
Core drilling indemnified costs  679  784 
Reimbursable general and administrative costs charged directly to general partner 398 592 
              
 
Total charges direct to general partner 605 1,485 1,795 3,177 
  
Income subject to 2% allocation of general partner interest 30,034 13,445 63,307 22,316  44,027 13,090 
General partner’s share of net income  2.0%  2.0%  2.0%  2.0%  2.0%  2.0%
              
  
General partner’s allocated share of net income before items directly allocable to general partner interest 600 268 1,266 446  881 262 
Incentive distributions paid to general partner 1,267 74 2,835 74 
Incentive distributions paid to general partner* 4,231 603 
Direct charges to general partner  (605)  (1,485)  (1,795)  (3,177)  (398)  (592)
Pre-partnership net income allocated to general partner  33,472 2,602 100,575   12,639 
              
  
Net income allocated to general partner $1,262 $32,329 $4,908 $97,918  $4,714 $12,912 
              
  
Net income $29,429 $45,432 $69,422 $119,714  $43,629 $25,137 
Net income allocated to general partner 1,262 32,329 4,908 97,918  4,714 12,912 
              
  
Net income allocated to limited partners $28,167 $13,103 $64,514 $21,796  $38,915 $12,225 
              
 
* RestatedUnder 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 discussed in Note 1.

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**On May 21, 2007, our outstanding Class B units were converted into common units onif all of the earnings for the period had been distributed. As a one-for-one basis. Accordingly, under EITF 98-05, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios” we should have made a $5.3 million non-cashresult, the general partner receives an additional allocation of income to the Class B units representing the Class B unit beneficial conversion feature in the second quarter of 2007. The $5.3 million beneficial conversion feature was computedquarterly periods where an assumed incentive distribution, calculated as the product of the 6,805,492 Class B units and the difference between the fair value of a privately placed common unit on the date of issuance ($36.59) and the issue price of a Class B unit ($35.81). This results in an $0.08 decrease from $0.56 per unit to $0.48 per unit on ourif all earnings per common unit for the second quarterperiod had been distributed, exceeds the actual incentive distribution. There are $8.4 million of 2007. Because we did not make this $5.3 million non-cash allocation inassumed incentive distributions for the second quarter of 2007, we have reflected this adjustment inthree months ended March 31, 2008 and no assumed incentive distributions for the year-to-date earnings per common unit through September 30,three months ended March 31, 2007. While this correction affects net income available to limited partners, it does not affect net income, cash flows nor does it affect total partners’ equity.
Under the “two class” method of computing earnings per share prescribed by SFAS No. 128, “Earnings Per Share,” earnings are to be allocated to participating securities as if all of the earnings for the period had been distributed. As a result, the general partner receives an additional allocation of income in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. The assumed incentive distribution for the three and nine months ended September 30, 2007 is $4.9 million and $5.7 million, respectively. There were no assumed incentive distributions for the three or nine months ended September 30, 2006. This results in an allocation of income for the calculation of earnings per limited partner unit as shown on the Consolidated Statements of Income.
Pursuant to the partnership agreement, income allocations are made on a quarterly basis; therefore, earnings per limited partner unit for the nine months ended September 30, 2007 and 2006 is calculated as the sum of the quarterly earnings per limited partner unit for each of the first three quarters of 2007 and 2006.     Common and subordinated unitholders sharehave always shared equally, on a per-unit basis, in the net income allocated to limited partners for the three and nine months ended September 30, 2007 and 2006.partners.
We paid or have authorized payment of the following cash distributions during 20062007 and 20072008 (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
2/14/2006 $0.3500  $2,452  $2,450  $   100     $5,002 
5/15/2006 $0.3800  $2,662  $2,660  $   109     $5,431 
8/14/2006 $0.4250  $6,204  $2,975  $  189   74  $9,442 
11/14/2006 $0.4500  $6,569  $3,150  $   202   199  $10,120 
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(a) $0.5500  $17,799  $3,850  $   487   2,211  $24,347 
                             
                  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 October 23, 2007April 24, 2008 to be paid on November 14, 2007May 15, 2008 to unitholders of record at the close of business on NovemberMay 7, 2007.2008.

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Note 4. Out of Period AdjustmentsAssets Held for Sale
     OutOur right of period adjustmentsway 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 correcta 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 our$11.3 million. The gathering system assets being sold are part of the Gathering and liabilities reflected in Revenues or Costs and expenses in our Consolidated Statements of Income are summarized in the following table (in thousands):
                 
  Three months ended Nine months ended
  September 30, September 30,
  2007 2006 2007 2006
      Increase (decrease) in net income    
                 
Gathering and Processing — West                
                 
Adjustment to property, plant and equipment and deferred revenue balances related to electronic flow measurement revenue recognition $(2,108) $  $(2,108) $ 
Adjustment to record condensate revenue on a current basis           1,900 
Adjustment to correct carrying value of prepaid right-of-way asset recorded from 2001 through 2006        (1,243)   
Adjustment to correct the 2006 incentive compensation accrual        899    
Adjustment to correct the asset retirement obligation originally recorded in 2005        (785)   
Adjustment to correct the accounts payable balance recorded in 2005           2,000 
Misstated accounts payable balances at June 30, 2006 corrected in the third quarter of 2006     (2,000)      
Misstated accounts payable balances at June 30, 2006 corrected in the third quarter of 2006     840       
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 Producer Services LLC
                
 September 30, December 31,  March 31, December 31, 
 2007 2006  2008 2007 
 (Unaudited)  (Unaudited) 
Current assets $61,048 $73,841  $75,773 $78,035 
Non-current restricted cash and cash equivalents 6,117 28,773  3,641 6,222 
Property, plant and equipment, net 378,552 355,304  363,889 368,228 
Current liabilities  (33,166)  (40,559)  (27,375)  (33,820)
Non-current liabilities  (13,993)  (3,728)  (12,450)  (12,216)
          
  
Members’ capital $398,558 $413,631  $403,478 $406,449 
          
                 
  Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
  2007  2006  2007  2006 
  (Unaudited) 
                 
Revenues:                
Affiliate $51,829  $38,755  $144,997  $113,992 
Third-party  8,281   8,663   31,098   28,462 
Costs and expenses:                
Affiliate  24,973   13,263   72,145   54,397 
Third-party  22,452   24,459   78,986   65,662 
Interest income  (389)  (608)  (1,472)  (1,835)
Loss on sale of operating assets        603    
Foreign exchange (gain) loss  (94)  166   (346)  (1,228)
             
                 
Net income $13,168  $10,138  $26,179  $25,458 
             
     As discussed in Note 1. Organization and Basis of Presentation, our consolidated financial statements and notes have been restated to include the additional 20% interest in Discovery, which we closed on in June 2007. However, certain cash transactions that occurred between Discovery and Williams before June 2007 that related to the additional 20% interest are not reflected in our Consolidated Statement of Cash Flows even though these transactions affect the carrying value of our restated investment in Discovery. A summary of these transactions is as follows (in thousands):
         
  Nine Months Ended
  September 30,
  2007 2006
Cash distributions from Discovery to Williams $9,035  $6,000 
       
         
  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 Long-Term DebtDecember 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 may borrow up to $75.0have a $450.0 million under Williams’ $1.5 billionsenior unsecured credit agreement with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit facility which is available for borrowings and letters of credit. Pursuant to an amendment dated May 9, 2007, borrowings undercredit and a $250.0 million term loan. Under certain conditions, the Williams facility mature in May 2012. Our $75.0 million borrowing limit under Williams’ revolving credit facility is available for general partnership purposes, including acquisitions, but onlymay be increased up to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At September 30, 2007, letters of credit totaling $28.0 million had been issued on behalf of Williams, none on behalf of the Partnership, by the participating institutionsan additional $100.0 million. Borrowings under this facilityagreement 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 loans were outstanding.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 29,20, 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 September 30, 2007,March 31, 2008, we havehad no outstanding borrowings under the working capital credit facility.
Long-Term DebtNote 7. Partners’ Capital
     In connection withOn January 9, 2008, we sold an additional 800,000 common units to the issuancesunderwriters 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 $600.0 millionoutstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of 7.25% senior unsecured notesWilliams converted into common units on December 13, 2006 and $150.0 million of 7.5% senior unsecured notesa one-for-one basis on June 20, 2006, sold in private debt placements to qualified institutional buyers in accordance with Rule 144A under the Securities Act and outside the United States in accordance with Regulations under the Securities Act, we entered into registration rights agreements with the initial purchasers of the senior unsecured notes. Under these agreements, we agreed to conduct a registered exchange offer of exchange notes in exchange for the senior unsecured notes or cause to become effective a shelf registration statement providing for resale of the senior unsecured notes. We launched exchange offers for both series on April 10, 2007 and they were successfully closed on May 11, 2007.February 19, 2008.
Note 7. Derivative Instruments and Hedging Activities8. Fair Value Measurements
Adoption of SFAS No.157
     Accounting policy
     We utilize derivativesSFAS 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 manageestimate 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 portion ofrecurring basis, primarily our energy commodity price risk. These instruments consist primarily of swap agreements. We execute these transactionsderivatives. Upon applying SFAS No. 157, we changed our valuation methodology to consider our non-performance risk in over-the-counter markets in which quoted prices exist for active periods. We reportestimating the fair value of derivatives,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 thoseitems 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

13


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 whichcertain financial instrument transactions and (ii) prospectively as of the normal purchasesdate 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 normal sales exception has been elected, on the Consolidated Balance Sheetrisks inherent in other current assets, other accrued liabilities, otherthe 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 other noncurrent liabilities.liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We determine the current and noncurrent classificationclassify fair value balances based on the timingobservability of expected future cash flowsthose inputs. The three levels of individualthe 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 accounting fordetermination 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 is governed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and depends on whether the derivative has been designated in a hedging relationship and what type of hedging relationship it is. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changesclassified as Level 3 in the fair value ofhierarchy for the derivative are recognized currently in other revenues.period January 1, 2008 through March��31, 2008.

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     For derivatives designated as a cash flow hedge,Fair Value Measurements Using Significant Unobservable Inputs
(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 effective portion of the change in fair value of the derivative isabove period are reported in other comprehensive loss and reclassified into earningsrevenues in the period in which the hedged item affects earnings. Any ineffective portionour Consolidated Statement of the derivative’s change in fair value is recognized currently in other revenues. Gains or losses deferred in accumulated other comprehensive loss associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive loss until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in accumulated other comprehensive loss is recognized in other revenues at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.Income.
Energy commodity cash flow hedges
     We are exposed to market risk from changes in energy commodity prices within our operations. Our Four Corners operation receives NGL volumes as compensation for certain processing services. To reduce our exposure to a decrease in revenues from the sale of these NGL volumes from fluctuations in NGL market prices, we entered into financials swap contracts for 8.8 million gallons of May through December 2007 forecasted NGL sales. These derivatives were designated in cash flow hedge relationships and are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. No ineffectiveness was recognized through September 30, 2007. There were no derivative gains or losses excluded from the assessment of hedge effectiveness through September 30, 2007. Based on recorded values at September 30, 2007, approximately $0.6 million of net losses will be reclassified into earnings in the fourth quarter. These recorded values are based on market prices of the commodities as of September 30, 2007. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized in 2007 will likely differ from these values. These gains or losses will offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
Note 8.9. Commitments and Contingencies
     Environmental Matters-Four Corners.Current New Mexicofederal regulations require that certain unlined liquid containment pits located near named rivers and catchment areas be taken out of use, and current state regulations requiredrequire 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 identifiedthat were slated for administrative closure under those regulations, and administrative closureregulations. We are presently awaiting agency approval is pendingof 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 $0.7$1.5 million at September 30, 2007March 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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     On April 11, 2007, the New Mexico Environment Department’s Air Quality Bureau (“NMED”) issued a Notice of Violation to Four Corners that alleges various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. We are investigating the matter and exchanging information with the NMED.
     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”)(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 $2.7$3.1 million has been incurred to date from the onset of the policy. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25.0 million. We do not expect to submit any claims under this insurance policy prior to its expected expiration date on April 30, 2008. In addition, under an omnibus agreement with Williams entered into at the closing of our IPO, Williams agreed to indemnify us for the $4.2 million deductible not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14.0 million cap on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy.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. We estimate that the approximate cost of this project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $0.2 million to $0.4 million per year following the completion of the remediation work. At September 30, 2007,March 31, 2008, we had accrued liabilities totaling $4.3$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, certainwe were named, along with other subsidiaries of Williams, including those that owned Four Corners, were named 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. We cannot reasonably estimate or quantify any potential liability. 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, including those that owned Four Corners.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. WeThe amount of any possible liability cannot be reasonably estimate or quantify any potential liability.estimated at this time.

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     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. On September 29,In 2006 we filed suit in the U.S. District Courtfederal court in Tulsa, Oklahoma against GEII, GEGeneral Energy Services, Inc., and Qualified Contractors, Inc. and; alleged, among other claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation,misrepresentation; and sought unspecified damages. On March 16,In 2007, all threethe defendants filed their answer, and GEII filed a counterclaimcounterclaims against us allegingthat alleged breach of contract and breach of the implied duty of good faith and fair dealing. We denied the counterclaim’s allegations in our answer to the counterclaim. Trial has been set for April 21,October 20, 2008. We are unable to quantify or estimate or quantify any potentialthe possible liability.
     Outstanding Registration Rights Agreement.Mid-America Pipeline Company.On December 13, 2006, we issued approximately $350.0 millionApril 28, 2008, Mid-America Pipeline Company, LLC (MAPL) filed suit in the District Court of common and Class B units inHarris County, Texas seeking a private equity offering. In connection with these issuances, we entered into a registration rights agreement withdeclaration that NGLs from Wamsutter LLC's Echo Springs Plant must be delivered to MAPL for transportation through the initial purchasers whereby we agreed to file a shelf registration statement providing for the resalelife of the common units purchasedplant. 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 common units issuedAgreement upon conversionproper notice. Williams has given MAPL notice of termination that will be effective May 5, 2008 and therefore denies any continuing obligation under the Class��B units. We filed the shelf registration statement on January 12, 2007, and it became effective on March 13, 2007. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis. If the shelf is unavailable for a period that exceeds an aggregate of 30 days in any 90-day period or 105 days in any 365 day period, the purchasers are entitled to receive liquidated damages. Liquidated damages with respect to each purchaser are calculated as 0.25% of the Liquidated Damages Multiplier per 30-day period for the first 60 days following the 90th day, increasing by an additional 0.25% of the Liquidated Damages Multiplier per 30-day period for each subsequent 60 days, up to a maximum of 1.00% of the Liquidated Damages Multiplier per 30-day period; provided, the aggregate amount of liquidated damages payable to any purchaser is capped at 10.0% of the Liquidated Damages Multiplier. The Liquidated Damages Multiplier, with respect to each purchaser, is (i) the product of $36.59 times the number of common units purchased plus (ii) the product of $35.81 times the number of Class B units purchased. We do not expect to pay any liquidated damages related to this agreement.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 eventruling to occur, there exists the possibility of a material adverse impacteffect on the results of operations in the period in which the eventruling 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 materiallymaterial adverse effect upon our future financial position.

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Note 9.10. 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 &     
 Gathering & Processing - NGL    Gathering & Processing - NGL   
 Processing - West Gulf Services Total  Processing - West Gulf Services Total 
 (In thousands)  (In thousands) 
Three Months Ended September 30, 2007:
 
Three Months Ended March 31, 2008:
 
 
Segment revenues $134,035 $521 $15,020 $149,576  $132,333 $567 $17,462 $150,362 
 
Product cost and shrink replacement 47,446  4,652 52,098 
Operating and maintenance expense 34,267 443 5,824 40,534  40,893 524 5,667 47,084 
Product cost and shrink replacement 45,791  3,058 48,849 
Depreciation, amortization and accretion 8,564 304 1,477 10,345  10,299 153 774 11,226 
Direct general and administrative expense 1,839  510 2,349  1,930  544 2,474 
Other, net 2,414  194 2,608  2,554  284 2,838 
                  
  
Segment operating income (loss) 41,160  (226) 3,957 44,891  29,211  (110) 5,541 34,642 
Equity earnings — Discovery Producer Services  7,902  7,902 
Equity earnings 21,194 13,621  34,815 
                  
  
Segment profit $41,160 $7,676 $3,957 $52,793  $50,405 $13,511 $5,541 $69,457 
                  
  
Reconciliation to the Consolidated Statements of Income:  
Segment operating income $44,891  $34,642 
General and administrative expenses:  
Allocated — affiliate  (8,670)
Third party — direct  (722)
Allocated-affiliate  (7,662)
Third party-direct  (668)
      
  
Combined operating income $35,499  $26,312 
      
  
Three Months Ended September 30, 2006*:
 
Three Months Ended March 31, 2007:
 
  
Segment revenues $132,603 $632 $13,347 $146,582  $120,428 $561 $12,826 $133,815 
  
Product cost and shrink replacement 39,675  2,520 42,195 
Operating and maintenance expense 29,950 399 7,220 37,569  33,097 550 8,866 42,513 
Product cost and shrink replacement 41,821  2,880 44,701 
Depreciation, amortization and accretion 10,035 300 609 10,944  12,175 304 699 13,178 
Direct general and administrative expense 2,838  279 3,117  1,821  498 2,319 
Other, net 2,260  182 2,442  2,384  190 2,574 
                  
  
Segment operating income (loss) 45,699  (67) 2,177 47,809  31,276  (293) 53 31,036 
Equity earnings — Discovery Producer Services  6,083  6,083 
Equity earnings 11,328 3,931  15,259 
                  
  
Segment profit $45,699 $6,016 $2,177 $53,892  $42,604 $3,638 $53 $46,295 
                  
  
Reconciliation to the Consolidated Statements of Income:  
Segment operating income $47,809  $31,036 
General and administrative expenses:  
Allocated — affiliate  (5,091)
Third party — direct  (560)
Allocated-affiliate  (7,224)
Third party-direct  (527)
      
  
Combined operating income $42,158  $23,285 
      
*Restated as discussed in Note 1.

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      Gathering &       
  Gathering &  Processing -  NGL    
  Processing - West  Gulf  Services  Total 
  (In thousands) 
Nine Months Ended September 30, 2007:
                
                 
Segment revenues $379,510  $1,541  $41,609  $422,660 
                 
Operating and maintenance expense  96,851   1,354   19,085   117,290 
Product cost and shrink replacement  127,779      7,942   135,721 
Depreciation, amortization and accretion  30,942   911   2,904   34,757 
Direct general and administrative expense  5,457      1,478   6,935 
Other, net  7,422      584   8,006 
             
                 
Segment operating income (loss)  111,059   (724)  9,616   119,951 
Equity earnings — Discovery Producer Services     15,708      15,708 
             
                 
Segment profit $111,059  $14,984  $9,616  $135,659 
             
Reconciliation to the Consolidated Statements of Income:                
Segment operating income             $119,951 
General and administrative expenses:                
Allocated — affiliate              (23,324)
Third party — direct              (2,385)
                
                 
Combined operating income             $94,242 
                
                 
Nine Months Ended September 30, 2006*:
                
                 
Segment revenues $376,069  $2,041  $42,393  $420,503 
                 
Operating and maintenance expense  93,570   872   21,481   115,923 
Product cost and shrink replacement  121,898      11,522   133,420 
Depreciation, amortization and accretion  29,801   900   1,809   32,510 
Direct general and administrative expense  8,599   9   815   9,423 
Other, net  2,612      555   3,167 
             
                 
Segment operating income  119,589   260   6,211   126,060 
Equity earnings — Discovery Producer Services     15,275      15,275 
             
                 
Segment profit $119,589  $15,535  $6,211  $141,335 
             
                 
Reconciliation to the Consolidated Statements of Income:                
Segment operating income             $126,060 
General and administrative expenses:                
Allocated — affiliate              (16,434)
Third party — direct              (1,674)
                
                 
Combined operating income             $107,952 
                
*Restated as discussed in Note 1.

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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 natural gas liquids (“NGLs”).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. The Four Corners system gathers and processes or treats approximately 37%ownership interests in Wamsutter, consisting of (i) 100% of the natural gas produced inClass A limited liability company membership interests and (ii) 50% of the San Juan Basin and connects withinitial Class C limited liability company membership interests (together, the five pipeline systems that transport natural gas to end markets fromWamsutter Ownership Interests). We account for the basin.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 ownsas an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such.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. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.
Executive Summary
     ThroughOur results for the thirdfirst quarter of 2007, we continued to realize strong NGL2008 reflect record per-unit commodity margins at Four Corners. GatheringCorners, which more than offset the negative impacts of severe winter weather, continued downtime related to the November 2007 fire at the Ignacio plant and processing revenues for Four Corners are slightly below 2006 dueincreased system losses. The severe weather reduced gathered volumes and limited our ability to lower volumes, but we expect our full-year gathering volumes will approximate 2006 levels. At Conway we continue to see strong demand for leased storageconnect new wells during much of the first quarter. Our two equity method investments, Wamsutter and new product upgrade services. Discovery’s income is comparable withDiscovery, also generated improved results over the prior year even though it had an exceptional first half of 2006 when it was processing volumes from damaged third-party facilities after Hurricanes Katrina and Rita. Our consolidated operating and maintenance expenses are slightly above 2006 levels, while we have seen significant increases in general and administrative expense. Year-over-year net income comparisons areyear. Wamsutter also significantly impacted by the interest on our $750.0faced severe winter weather challenges, but distributed $22.7 million in long-term debt issued in June 2006 and December 2006 to finance a portion of our acquisition of Four Corners. Additionally, our results reflectcash distributions during the impact of adjustments to our operating costs and expenses, which are itemized in Note 4 of the Notes to our Consolidated Financial Statements.
Recent Events
Conversion of Class B Units. On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis by a majority vote of common units eligible to vote.
Additional Investment in Discovery.On June 28, 2007,we closed onfirst full quarter following the acquisition of an additional 20% limited liability company interest in Discovery for aggregate consideration of $78.0 million pursuant to an agreement with Williams Energy, L.L.C. and Williams Energy Services, LLC. This transaction was effective July 1, 2007.Because this additional 20% interest inour ownership interests. Discovery was purchased from an affiliateable to significantly increase its quarterly cash distribution to a record $16.8 million. Based on this combined performance, we continued our record of The Williams Companies, Inc. (“Williams”),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 transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes and this discussion of results of operations have been restated to reflect the combined historical results of our investment in Discovery throughoutfirst-quarter 2007 distribution.

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the periods presented. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment.
Results of Operations
Consolidated Overview
     The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2007,March 31, 2008, compared to the three and nine months ended September 30, 2006.March 31, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion. All prior period information in the following discussion and analysis of results of operations has been restatedrecast to reflect the combined historical results of our 100% interestinvestments in Discovery and Wamsutter throughout the periods presented following our acquisition in Four Corners in 2006 and our 60% equityof the additional 20% interest in Discovery.Discovery and the Wamsutter Ownership Interests in June and December 2007, respectively.
                                    
 Three months ended Nine months ended % Change  Three months ended   
 September 30, % Change from September 30, from  March 31, % Change from 
 2007 2006 2006(1) 2007 2006 2006(1)  2008 2007 2007(1) 
 (Thousands) (Thousands)  (Thousands) 
  
Revenues $149,576 $146,582  +2% $422,660 $420,503  +1% $150,362 $133,815  +12%
  
Costs and expenses:  
Product cost and shrink replacement 48,849 44,701  -9% 135,721 133,420  -2% 52,098 42,195  -23%
Operating and maintenance Expense 40,534 37,569  -8% 117,290 115,923  -1%
Operating and maintenance expense 47,084 42,513  -11%
Depreciation, amortization and accretion 10,345 10,944  +5% 34,757 32,510  -7% 11,226 13,178  +15%
General and administrative Expense 11,741 8,768  -34% 32,644 27,531  -19%
General and administrative expense 10,804 10,070  -7%
Taxes other than income 2,474 2,352  -5% 7,214 6,392  -13% 2,505 2,114  -18%
Other (income) expense 134 90  -49% 792  (3,225) NM 
Other expense 333 460  +28%
              
  
Total costs and expenses 114,077 104,424  -9% 328,418 312,551  -5% 124,050 110,530  -12%
              
 
Operating income 35,499 42,158  -16% 94,242 107,952  -13% 26,312 23,285  +13%
Equity earnings — Wamsutter 21,194 11,328  +87%
Equity earnings — Discovery 7,902 6,083  +30% 15,708 15,275  3% 13,621 3,931 NM 
Interest expense  (14,284)  (3,271) NM  (43,084)  (4,155) NM   (17,736)  (14,390)  -23%
Interest income 312 462  -32% 2,556 642 NM  238 983  -76%
              
  
Net income $29,429 $45,432  -35% $69,422 $119,714  -42% $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 September 30, 2007March 31, 2008 vs. three months ended September 30, 2006March 31, 2007
     Revenues increased $3.0$16.5 million, or 2%12%, due primarily to higher revenues in our Gathering and Processing — West segment and our NGL Services segments.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 and other revenues.volumes. Revenues increased in our NGL Services segment increased due primarily to higher product sales, fractionation and storage and product upgrade fees.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 $4.1$9.9 million, or 9%23%, due primarily to increased NGL purchases from producersincreases in our Gathering and Processing — West segment. This fluctuation is discussed in detail in the “—

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Results of Operations — Gathering and Processing — West” section.
     Operating and maintenance expense increased $3.0 million, or 8%, due primarily to higher expense inboth our Gathering and Processing — West segment partially offset by lower expense inand our NGL Services segment. OperatingProduct cost and maintenance expenseshrink 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 system losses, leased compression and rent expense,average natural gas prices, partially offset by lower materialsshrink requirements due to lower processing volumes. Product cost and supplies and outside services costs. Operating and maintenance expenseshrink replacement in our NGL Services segment decreasedincreased due primarily to lower product losses from cavern empties.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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     GeneralOperating and administrativemaintenance expense increased $3.0$4.6 million, or 34%11%, due primarily to higher Williams technical support servicessystem losses and other charges allocated by Williams to us for various administrative support functions.
     Operating income decreased $6.7 million, or 16%, due primarily to higher general and administrative and operating and maintenance expense.
     Equity earnings from Discovery increased $1.8 million, or 30%, due primarily to higher NGL gross margins, largely offset by higher operating and maintenance expense. This increase is discussed in detail in the “— Resultsrevaluation of Operations — Gathering and Processing — Gulf” section.
     Interest expense increased $11.0 million due to interest on our $600.0 million senior unsecured notes issued in December 2006 to finance a portion of our acquisition of Four Corners.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
     Revenues increased $2.2 million, or 1%, due primarily to higher product salesimbalances in our Gathering and Processing — West segment, partially offset by lower gathering, processinga favorable change in gains and other revenues in the same segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.
     Product cost and shrink replacement increased $2.3 million, or 2%, due primarily to increased NGL purchases from producers in our Gathering and Processing — West segment, partially offset by decreasedlosses on product sales volumesimbalances in our NGL Services segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.
     Operating and maintenance expense increased $1.4The $2.0 million, or 1%15%, due primarily to higher expensedecrease in Depreciation, amortization and accretion reflects $2.0 million of first-quarter 2007 adjustments in our Gathering and Processing — West segment, partially offset by lower expense in our NGL Services segment. Operating and maintenance expense in our Gathering and Processing — West segment increased due primarily to higher fuel, leased compression and rent expense, largely offset by lower maintenance and supplies costs. Operating and maintenance expense in our NGL Services segment decreased due primarily to lower fuel and power costs related to the lower fractionator throughput. These fluctuations areThis fluctuation is discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.section.
     The $2.2Operating income increased $3.0 million, or 7%13%, increasedue primarily to higher per-unit NGL sales margins in Depreciation, amortizationour Gathering and accretion reflects $2.0 million of first quarter 2007 right-of-way amortizationProcessing — West segment and asset retirement obligation adjustmentsincreased 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.
     General and administrative expenseEquity earnings from Wamsutter increased $5.1$9.9 million, or 19%87%, due primarily to higher Williams technical support servicesper-unit NGL sales margins on higher NGL sales volumes and other charges allocated by Williams to us for various administrative support functions.
     Taxes other than income increased $0.8 million, or 13%, due primarily to an increaseis discussed in New Mexico gas processor’s taxdetail in the “— Results of Operations — Gathering and Processing — West segment.
     Other (income) expense, changed from $3.2 millionWest” section. Please read Note 5 Equity Investments of our Notes to Consolidated Financial Statements, for a discussion of how Wamsutter allocates its net income in 2006 to $0.8 million expense in 2007, due primarily to a $3.6 million gain in 2006 on the sale of property in the Gathering and Processing — West segment.

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     Operating income declined $13.7 million, or 13%, due primarily to higher general and administrative expense, the absence of the 2006 gain on the sale of property and higher depreciation, amortization and accretion expense.between its member owners including us.
     Equity earnings from Discovery increased $0.4$9.7 million, or 3%,also due primarily to higher per-unit NGL gross processingsales margins that offset lower fee-based revenues following the loss of 2006 revenues associated with providing services for stranded gas after the 2005 hurricanes. Discovery’s results areon higher NGL sales volumes. This increase is discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.
     Interest expense increased $38.9$3.3 million, or 23%, due to interest on our $750.0$250.0 million senior unsecured notesterm loan issued in June and December 20062007 to finance a portion of our acquisition of Four Corners.Wamsutter Ownership Interests.

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     Interest income increased from $0.6 million to $2.6 million due to higher cash balances during the first and second quarters of 2007.
Results of operations — Gathering and Processing — West
     The Gathering and Processing — West segment includes our Four Corners natural gas gathering, processing and treating assets.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  Nine months ended 
  September 30,  September 30, 
  2007  2006  2007  2006 
  (Thousands) 
                 
Revenues $134,035  $132,603  $379,510  $376,069 
                 
Costs and expenses, including interest:                
Product cost and shrink replacement  45,791   41,821   127,779   121,898 
Operating and maintenance expense  34,267   29,950   96,851   93,570 
Depreciation, amortization and accretion  8,564   10,035   30,942   29,801 
General and administrative expense — direct  1,839   2,838   5,457   8,599 
Taxes other than income  2,278   2,170   6,628   5,842 
Other (income) expense, net  136   90   794   (3,230)
             
                 
Total costs and expenses  92,875   86,904   268,451   256,480 
             
                 
Segment profit $41,160  $45,699  $111,059  $119,589 
             
Three months ended September 30, 2007March 31, 2008 vs. three months ended September 30, 2006March 31, 2007
     Revenues increased $1.4$11.9 million, or 1%,10% percent, due primarily to $17.6 million higher product sales partially offset by $5.6 million lower gathering and processing and other revenues. The significant components of the revenue fluctuations are addressed more fully below.revenue.
     Product sales revenues increased $6.7 million due primarily to:
  $4.3 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $4.3 million discussed below.
$3.316.6 million related to a 8%59% increase in average NGL sales prices realized on sales of NGLs which we received under certainkeep-whole and percent-of-liquids processing contracts;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.

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     These product sales increases were partially offset by $0.8$7.6 million lower revenues related to a 2%21% decrease in NGL volumes that Four Corners received under certainkeep-whole and percent-of-liquids processing contracts.
     Miscellaneous revenues The decreased $3.7 millionNGL volumes were due primarily to a $3.5 million outlower processing volumes caused by prolonged, severe winter weather during January and February of period revenue recognition correction for electronic flow measurement fees recorded prior to 2003 that should have been deferred2008 and recognized over the contract period. See Note 4impact of the Notes to Consolidated Financial Statements.fire at the Ignacio gas processing plant in November 2007. The amount shown in Note 4 for this correction is net of the related $1.4 million decrease in depreciation expense.plant was shut down until January 18, 2008.
     GatheringFee-based gathering and processing revenues decreased $1.8$5.6 million, or 3%9%, due primarily to a $1.2$4.8 million decrease in the average rate charged for these services and $0.6 millionlower revenue from a 1%an 8% decrease in gathered and processed volumes.volumes and an $0.8 million decrease from 2007 billings of back charges on a customer contract for 2005 and 2006. The decrease indecreased gathered and processed volumes were also caused by the average rate was due primarily to a lower rate on one of our agreements that is adjusted annually based on the price of natural gas on January 1. The price of natural gas was substantially higher on January 1, 2006 than on January 1, 2007.weather and fire-related impacts discussed previously.
     Product cost and shrink replacement increased $4.0$7.8 million, or 9%20%, due primarily to a $4.3to:
$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 corresponding increase in product sales revenuesdecreased NGL volumes received under Four Corners’ keep-whole processing contracts discussed above.
     Operating and maintenance expense increased $4.3$7.8 million, or 14%24%, due primarily to:
$5.5 million higher non-shrink natural gas purchases caused primarily by $3.7 million higher system losses. During the third quarter of 2007 our volumetric loss, as a percentage of total volume received, was higher than in 2006. System losses are an unpredictable component of our operating costs. Given the scale of throughput on Four Corners’ system, relatively small percentage product losses can generate a fairly significant impact to operating costs.
$1.7 million higher leased compression costs under agreements that are currently being renegotiated but are at present under month-to-month terms.
$1.3 million higher rent expense related to the purchase of a temporary special business license upon the expiration of a right-of-way agreement.
     Partially offsetting these increases were $4.2to $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 lower materials2007.  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 suppliesFebruary 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 outside servicesgathering fuel expense.  Product imbalance revaluations fluctuate with changes in the underlying price of natural gas and with changes in imbalance levels. Gathering fuel expense includingwas unfavorably impacted by the absence ofweather and operational inefficiencies caused by the $2.0 million third quarter 2006 adjustment discussed in Note 4 offire at the Notes to Consolidated Financial Statements.Ignacio gas processing plant previously mentioned.
     The $1.5$1.9 million, or 15%, decrease in depreciation, amortization and accretion expense includes $1.4is due primarily to the $2.0 million lower expense resulting from the electronic flow measurement fees correction mentioned previously.of first-quarter 2007 right-of-way amortization and asset retirement obligations corrections.
     General and administrative expense — directSegment operating income decreased $1.0$2.1 million, or 35%7%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.
     Segment profit decreased $4.5 million, or 10%, due primarily to $4.3$7.8 million higher operating and maintenance expense $3.7and $5.6 million lower miscellaneous revenue and $1.8 million lowerfee-based gathering and processing revenues, partiallyrevenue. These were substantially offset by $2.7$9.8 million higher product sales margins $1.5resulting primarily from sharply increased per-unit margins on lower NGL sales volumes and $1.9 million lower depreciation expense including the effect of the out of period correction and $1.0 million lower direct general and administrative expense.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
     Revenues increased $3.4 million, or 1%, due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. The significant components of the revenue fluctuations are addressed more fully below.

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     Product sales revenues increased $8.4 million due primarily to:
$6.9 million related to a 6% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts.
$5.5 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $5.5 million discussed below.
     These product sales revenue increases were offset by:
$2.6 million decrease in condensate and liquefied natural gas sales due primarily to the absence of the $1.9 million second quarter 2006 adjustment discussed in Note 4 of the Notes to Consolidated Financial Statements. Prior to 2006, condensate revenue had been recognized two months in arrears.
$1.3 million related to a 1% decrease in NGL volumes that we received under certain processing contracts.
     Gathering and processing revenues decreased $2.2 million, or 1%, due primarily to a 1% decrease in average gathered and processed volumes.
     Miscellaneous revenues decreased $2.8 million due primarily to the $3.5 million out of period revenue recognition correction mentioned previously.
     Product cost and shrink replacement increased $5.9 million, or 5%, due primarily to a $5.5 million increase from third party producers who elected to have us purchase their NGLs, which was offset by the corresponding increase in product sales discussed above.
     Operating and maintenance expense increased $3.3 million, or 4%, due primarily to:
$3.8 million higher leased compression costs under agreements that are currently being renegotiated but are at present under month-to-month terms.
$3.1 million higher non-shrink natural gas purchases caused primarily by higher fuel costs, partially offset by lower system losses.
$2.6 million higher right-of-way expense related to our special business licenses with the Jicarilla Apache Nation.
     Partially offsetting these increases were $6.2 million in lower costs including $5.8 million lower maintenance costs and supplies purchases.
     The $1.1 million, or 4%, increase in depreciation, amortization and accretion expense includes $2.0 million of first quarter 2007 right-of-way amortization and asset retirement obligation adjustments, partially offset by $1.4 million lower expense related to the electronic flow measurement fee correction discussed previously.
     General and administrative expense — direct decreased $3.1 million, or 37%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.
     Other (income) expense, changed unfavorably by $4.0 million due primarily to a $3.6 million gain recognized on the sale of the LaMaquina treating facility in the first quarter of 2006.
     Taxes other than income increased $0.8 million, or 13%, due primarily due to increases in the New Mexico gas processor’s tax.

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     Segment profit decreased $8.5 million, or 7%, due primarily to the net $7.1 million unfavorable impact of 2006 and 2007 adjustments discussed in Note 4 of the Notes to the Consolidated Financial Statements and the absence of the $3.6 million gain on the sale of the LaMaquina treating facility in 2006, partially offset by $3.1 million lower general and administrative expense — direct.expense.
Outlook
     Throughput volumes on our Four Corners gathering, processing and treating system are an important component of maximizing its profitability. Throughput volumes from existing wells connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels we must continually obtain new supplies of natural gas.
  We anticipateanticipated that gathered volumesgrowth capital investments we completed in the fourth quarter of 2007 will continue to increase over the previous quarters of 2007 due to improved operating conditions, sustainedsupport 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 existing customers.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. We expectBased on first-quarter 2008 prices for NGLs and natural gas combined with the hedging program described below, per-unit margins in 2007 will remain higher in relation to five-year historical averages, and will likely2008 could meet or exceed the record levels realized in 2006. Additionally, we anticipate2007. However, the prices of NGLs and natural gas can quickly fluctuate in response to a variety of factors that our contract mixare impossible to control and, commodity management activities at Four Corners will continue to allow us to realize greater margins relative to industry benchmark averages.in particular, NGL pricing is typically impacted negatively by recessionary economic conditions.
 
  In May 2007,Throughout the remainder of 2008, we hedged 8.8may 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 May through December 2007our monthly forecasted NGL sales using financial swapand 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 rangehedged margin of fixed prices$25.0 million or an average of $1.15 to $1.62$0.51 per gallon depending on these NGL sales in 2008. The primary purpose of these hedges is to mitigate risk associated with ethane sales derived from keep-

23


whole processing arrangements. Of the specific product. We receive5.4 million gallons, 4.2 million are ethane sales. The average hedged margin on these forecasted keep-whole NGL sales exceeds the underlyingaverage margin realized on keep-whole NGL gallons as compensationsales for processing services provided at Four Corners. We have designated these derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”2007.
 
  We anticipate that operating costs, excluding compression, gathering fuel and system gains and losses, will remain stable as compared to 2006.2007. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of our Four Corners 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”),(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 DecemberAugust 31, 2007. We2008, and are engaged in discussionsnegotiating with the JAN designed 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 inof 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 of our gathering assets which are located on or are isolated by the JAN lands. Provided the parties are ablewill allow us to reach an acceptable value on the sale of the subject gathering assets, our expectation is that we will nonetheless maintain partial revenues associated with gathering and processing downstream ofservices for gas produced from the JAN lands and continue to operatecontinued operations of the gathering assets on the JAN lands for an undetermined periodthrough at least 2009. We believe the expected proceeds from the sale of time beyond December 31, 2007.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'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

26


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. This 60% ownership interest includes the 40% interest we have owned since our initial public offering (“IPO”) and the additional 20% ownership acquired from Williams on June 28, 2007. This transaction was effective July 1, 2007. Because this additional 20% interest in Discovery was purchased from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes and this discussion of results of operations have been restated to reflect the combined historical results of our investment in Discovery throughout the periods presented. We continue to account for this investment under the equity method due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment.
                        
 Three months ended Nine months ended  Three months ended 
 September 30, September 30,  March 31, 
 2007 2006 2007 2006  2008 2007 
 (Thousands)  (Thousands) 
  
Segment revenues $521 $632 $1,541 $2,041  $567 $561 
  
Costs and expenses:  
Operating and maintenance expense 443 399 1,354 872  524 550 
Depreciation 304 300 911 900  153 304 
General and administrative expense — direct    9 
 
              
  
Total costs and expenses 747 699 2,265 1,781  677 854 
              
  
Segment operating income (loss)  (226)  (67)  (724) 260 
Equity earnings — Discovery (60%) 7,902 6,083 15,708 15,275 
Segment operating loss  (110)  (293)
Equity earnings — Discovery 13,621 3,931 
              
  
Segment profit $7,676 $6,016 $14,984 $15,535  $13,511 $3,638 
              
Carbonate Trend
     Segment operating loss for the three and nine months ended September 30, 2007 increaseddecreased $0.2 million, and $1.0 million, respectively, as compared to the three and nine months ended September 30, 2006,or 62%, due primarily to higher insurance premiums related tolower depreciation following the increased hurricane activityproperty impairment recognized in the Gulf Coast region in recent years. In addition, gathering revenues decreased due to 20% and 27% declines in average daily gathered volumes, respectively. These volumetric declines are caused by normal reservoir depletion that was not offset by new sourcesfourth quarter of throughput.2007.

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Discovery Producer Services — 100 %
                 
  Three months ended  Nine months ended 
  September 30,  September 30, 
  2007  2006  2007  2006 
  (Thousands) 
                 
Revenues $60,110  $47,418  $176,095  $142,454 
                 
Costs and expenses, including interest:                
Product cost and shrink replacement  34,538   26,862   107,945   84,310 
Operating and maintenance expense  5,751   3,864   21,265   13,918 
Depreciation and accretion  6,243   6,380   19,234   19,133 
General and administrative expense  579   372   1,702   1,606 
Interest income  (389)  (608)  (1,472)  (1,835)
Other (income) expense, net  220   410   1,242   (136)
             
                 
Total costs and expenses, including interest  46,942   37,280   149,916   116,996 
             
                 
Net income $13,168  $10,138  $26,179  $25,458 
             
                 
Williams Partners’ 60% interest — Equity earnings per our Consolidated Statements of Income                
  $7,902  $6,083  $15,708  $15,275 
             
     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 September 30, 2007March 31, 2008 vs. three months ended September 30, 2006March 31, 2007
     Revenues increased $12.7$34.7 million, or 27%66%, due primarily to increased product sales. Product sales increased $14.7$33.6 million due primarily to $8.5 million from higher NGL volumes sold which Discovery received under certain processing contracts, $3.9 million increase in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contracts and $2.3 million related to higher NGL prices Discovery received for these NGLs.
     These product sales increases were partially offset by:resulting from:
  $0.6 million lower transportation revenues due to $1.920.3 million from lower average transportation rates partially offset by $1.3 million from105% higher transportation volumes.NGL volumes due primarily to an increase in volumes processed under keep-whole processing arrangements;
 
  Fee-based gathering, processing and fractionation revenues that decreased $1.6$11.7 million due primarily to reduced fee-based revenues related to processing Texas Eastern Transmission Company (“TETCO”) open season volumes. In 2006 the open season agreements included fee-based processing and fractionation. Our current agreement with TETCO includes processing services baseda 29% increase in average NGL sales prices realized on a percent-of-liquids contract, where thesales of NGLs we take as compensation are reflected in the higher product sales discussed above.
     Product cost and shrink replacement increased $7.7 million, or 29%, due primarily to $3.8 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $2.6 million for higher volumetric natural gas requirements from increased processing activity.
     Operating and maintenance expense increased $1.9 million, or 49%, due primarily to $0.7 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years and other increased repair, maintenance and labor expenses.
     Net income increased $3.0 million, or 30%, due primarily to $6.9 million higher gross NGL margins attributable to higher NGL sales volumes, partially offset by $1.6 million lower fee-based gathering, processing and fractionation revenues, $0.6 million lower transportation revenues and $1.9 million higher operating and maintenance expense.

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Nine months ended September 30, 2007 vs. Nine months ended September 30, 2006
     Revenues increased $33.6 million, or 24%, due primarily to $44.5 million increased product sales, partially offset by the reduction of $10.1 million in fee-based transportation, gathering, processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas Pipeline (“TGP”) and the TETCO open season agreements. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006 and in October 2006 we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.
Product sales increased $44.5 million, primarily due to $31.8 million from higher NGL volumes soldwhich Discovery received under certain processing contracts, including the TETCO agreement, $6.2 millioncontracts. This increase resulted from higher average NGLgeneral increases in market prices received for these NGLs, $3.9 million increase in NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs under an option in their contractscommodities between the two periods; and $2.6 million from higher sales of excess fuel and shrink replacement gas. See below for the related changes in product cost and shrink replacement for each of these product sales increases.
 
  Fee-based gathering,$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 and fractionation revenues decreased $7.5 million due primarily to reduced fee-based revenues related to processing the TGP and TETCO open seasons volumes discussed above. In 2006 the open season agreements included fee-based processing and fractionation. Our current agreement with TETCO includes processing services based on a percent-of-liquids contract, where the NGLs we take as compensation are reflected in the higher product sales discussed above.activity;
 
  Transportation revenues decreased $2.5 million, including $3.7 million in reduced fee-based revenues related to the absence of TGP and TETCO open season agreements discussed above.
     Product cost and shrink replacement increased $23.6 million, or 28%, due primarily to $14.5 million higher volumetric natural gas requirements from increased processing activity, $3.7 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $3.0$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 sales discussedmentioned above.
     OperatingGeneral and maintenanceadministrative expense increased $7.3$1.2 million or 53%, due primarily to $3.1 million higher property insurance premiums related to the increased hurricane activitya proposed increase in Discovery’s management fee charged by Williams. The management fee is in the Gulf Coast region in prior years, $1.6 million from costs related to decommissioning two pipelines and other increased repair, maintenance and labor expenses.process of being re-negotiated effective January 1, 2008 as discussed below.
     Other (income) expense,income, net changed from $0.1increased $2.9 million of income in 2006 to $1.2 million of expense in 2007. The increased expense was due primarily to the loss on retirement for the two pipelines that were decomissioned and a decrease in non-cash foreign currency transaction gains. The non-cash foreign currency transaction gains resulted$3.5 million from the revaluationreversal of restricted cash accounts denominatedamounts previously reserved from 1998 through 2003 for system fuel and lost and unaccounted for gas in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, forconnection with the construction of the Tahiti pipeline lateral expansion project.recently approved FERC settlement filing.
     Net income increased $0.7$16.2 million or 3%, due primarily to $20.9$14.9 million higher gross NGLproduct sales margins resulting primarily from sharply increased per-unit margins on higher NGL sales volumes substantiallyand $2.9 million for higher other income, net, partially offset by $11.2 million lower fee-based transportation, gathering, processing and fractionation revenues from the absences of the 2006 TGP and TETCO open season agreements, $7.3$1.2 million higher operatinggeneral and maintenance expense and $1.3 million higher otheradministrative expense.

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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.
The Tahiti pipeline lateral expansion project is currently on schedule. The pipeline was installed on the sea bed in February 2007. Chevron had scheduled initial throughput to begin in mid-2008, but recently announced that it will face delays because of metallurgical problems discovered in the facility’s mooring shackles. Chevron recently announced that it expects first production by the third quarter of 2009. Discovery’s revenues from the Tahiti project are dependent on receiving throughput from Chevron. Therefore, delays Chevron experiences in bringing their production online will impact the initial timing of revenues for Discovery.
Effective June 1, 2007, Discovery amended the 100 BBtu/d contract with TETCO to increase the volume to 200 BBtu/d through October 31, 2007. At the conclusion of this agreement, we expect continued throughput of about 150 BBtu/d through the first quarter of 2008 at which time we expect no further volumes under this agreement. Current flowing volumes are approximately 250 BBtu/d.
  With the current oil and natural gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the limited availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits the ability of producers to bring identified reserves to market quickly. This will prolong the timeframe over which these reserves will be developed. We expect Discovery to be successful in competing for a portion of these new volumes.
 
  DiscoveryDiscovery’s Tahiti pipeline lateral was installed on the sea bed in February 2007. Chevron has contracted additionalrecently 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 70 BBtu/d and 140 BBtu/drevenues for October and November 2007, respectively, under short-term keep-whole agreements with shippers.Discovery.
 
  ATP Oil & Gas Corporation completed modificationsThe 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 Gomez facilityMC 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 October 2007, whichearly summer 2008.
We expect Discovery’s 2008 results will increasebe favorably impacted by approximately $3.0 million due to its recently approved FERC rate filing pertaining to the volumes to approximately 75 BBtu/d.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 additional throughputthree 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 25 BBtu/d increasing to approximately 50 BBtu/d in 2008 with Energy Partners Limited.$1.0 million per quarter and the increase has been recognized as part of Discovery’s first-quarter results.

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Results of Operations NGL Services
     The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50%50 percent interest in the Conway fractionator.
                        
 Three months ended Nine months ended  Three months ended 
 September 30, September 30,  March 31, 
 2007 2006 2007 2006  2008 2007 
 (Thousands)  (Thousands) 
Segment revenues $15,020 $13,347 $41,609 $42,393  $17,462 $12,826 
  
Costs and expenses:  
Product cost 4,652 2,520 
Operating and maintenance expense 5,824 7,220 19,085 21,481  5,667 8,866 
Product cost 3,058 2,880 7,942 11,522 
Depreciation and accretion 1,477 609 2,904 1,809  774 699 
General and administrative expense — direct 510 279 1,478 815  544 498 
Other expense, net 194 182 584 555  284 190 
              
  
Total costs and expenses 11,063 11,170 31,993 36,182  11,921 12,773 
              
  
Segment profit $3,957 $2,177 $9,616 $6,211  $5,541 $53 
              
Three months ended September 30, 2007March 31, 2008 vs. three months ended September 30, 2006March 31, 2007
     Segment revenues increased $1.7$4.6 million, or 13%36%, due primarily to higher storageproduct sales, fractionation and product upgrade feestorage revenues. The significant components of the revenue fluctuations are addressed more fully below.
Storage
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 $0.8 million due primarily to higher average storage rates.
Low sulfur natural gasoline upgrade fees increased $0.7 million. This upgrade service began in late 2006.
     Operating and maintenance expense decreased $1.4 million or 19%, due primarily to $0.5 millionthe expiration of product lossesa fractionation contract with a cap on cavern emptiesthe per-unit fee, which limited our ability to pass through increases in the third quarter of 2007 comparedfractionation fuel expense to $1.5 million of product losses in the third quarter of 2006.this customer.

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     Depreciation and accretion expense
Storage revenues increased $0.9 million due primarily to a correction made in the third quarter of 2007 to year-to-date depreciation and accretion expense related to asset retirement obligation assumption changes.
     Segment profit increased $1.8 million, or 82%, due primarily to the $1.4 million decrease in operating and maintenance expense discussed above and higher average storage and product upgrade fee revenues partially offset by higher depreciation and accretion expense.
Nine months ended September 30, 2007 vs. nine months ended September 30, 2006
     Segment revenues decreased $0.8 million, or 2%, due primarily to lower product sales and fractionation revenues, partially offset by higherfrom additional storage and product upgrade fee revenues. The significant components of the revenue fluctuations are addressed more fully below.leases.
Product sales decreased $4.0 million due to lower sales volumes. This decrease was offset by the related decrease in product cost discussed below.
Fractionation revenues decreased $2.4 million due primarily to 17% lower fractionation volumes and 9% lower rates. Fractionation throughput was lower during 2007 due to a customer’s decision to fractionate a

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percentage of their volumes outside of the Mid-Continent region for three months. This decision was based on current prices being paid for fractionated products outside of the Mid-Continent region. The lower fractionation rates relate to the pass through to customers of decreased fuel and power costs.
Storage revenues increased $3.0 million due primarily to more contracted storage and higher average storage rates for all of 2007.
Other revenue increased $2.5 million due primarily to low sulfur natural gasoline upgrade fees. This upgrade service began in late 2006.
     Product cost decreased $3.6increased $2.1 million, or 31%85%, due to the lowerhigher product sales volumes discussed above, resultingabove. This resulted in a net margin loss of $0.4$0.2 million.
     Operating and maintenance expense decreased $2.4$3.2 million, or 11%36%, due primarily to lower fuela $1.4 million first- quarter 2007 product imbalance valuation adjustment and power costs related to the lower fractionator throughput.
     Depreciationa $1.4 million improvement in gains and accretion expense increased $1.1 million, or 61%, due primarily to asset retirement obligation assumption changes.losses on storage and fractionation product imbalances.
     Segment profit increased $3.4$5.5 million or 55%, due primarily to the $2.4 million decrease inhigher fractionation and storage revenues and lower operating and maintenance expense discussed above and higher storage and product upgrade fee revenues, partially offset by lower fractionation revenues and higher depreciation and accretion expense.costs.
Outlook
Based on year-to-date storage lease renewals, we expect 2007 storage revenues will exceed 2006 levels due to strong demand for propane and butane storage as well as higher priced specialty storage services.
We continue to execute 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 2007 and 2008 to ensure we remain on track to meet the regulatory compliance requirements. Our forecast for 2007 is to workover approximately 57 caverns (both complete and partial) compared to 51 cavern workovers (38 complete and 13 partial) in 2006. Through September 30, 2007 we completed 33 workovers with another 19 caverns out of service for workovers.
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. 

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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 20072008 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 capital requirementsuses of cash for the remainder of 20072008 to be:
  Maintenance and expansion capital expenditures for our Four Corners and Conway assets;
 
  ExpansionContributions we must make to Wamsutter LLC to fund certain of its expansion capital expenditures for ourexpenditures;
Completion of the Four Corners assets;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 20072008 distributions to its members (all amounts in thousands):
         
  Total Distribution to  
Date of Distribution Members Our Share**
1/30/07 $9,000  $3,600 
4/30/07 $16,000  $6,400 
6/22/07* $11,173  $4,469 
7/30/07 $9,000  $3,600 
10/31/07 $14,000  $8,400 
         
  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
     
*Special distribution Discovery made after receipt of insurance proceeds.
**On June 28, 2007,we closed on the acquisition of an additional 20% limited liability company interest in Discovery. Because this acquisition was effective July 1, 2007, we did not begin to receive 60% of Discovery’s distributions until October 2007.
     In 2005, Discovery’s facilitiesOn November 28, 2007 the Ignacio gas processing plant sustained significant damages from Hurricane Katrina.a fire. The estimated total cost for hurricane-relatedfire-related repairs is approximately $21.5$29.0 million, including $19.9$28.0 million in potentially reimbursable expenditures in excess of the insurance deductible. Of this amount, $20.0$15.0 million has been spent as of September 30, 2007. Discovery isincurred through March 31, 2008. We are funding these repairs with cash flows from operations, and isare seeking reimbursement from itsour insurance carrier.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 September 30, 2007, Discovery has received $16.1 millionproceeds from the insurance carrierssale 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 has an insurance receivable balance of $3.9 million.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 September 30, 2007March 31, 2008, we have received $3.4$5.7 million from Williams for indemnified items since inception of the agreement in

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August 2005. Thus, approximately $10.6$8.3 million remains available for reimbursement of our costs on these items. Amounts expected to be incurred in 2007 related to these indemnifications are as follows:
$3.8 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facilities. Approximately $2.0 million has been received through September 30, 2007.
$1.2 million for our initial 40% share of Discovery’s costs for marshland restoration and repair or replacement of Paradis’ emission-control flare. Approximately $0.4 million has been received through September 30, 2007.
We expect all costs to repair the partial erosion of the Carbonate Trend pipeline overburden caused by Hurricane Ivan in 2004 will be recoverable from insurance, but to the extent they are not, we will seek indemnification under the omnibus agreement.
Additionally, under the omnibus agreement, we will receive (1) an annual credit for general and administrative expenses of $2.4 million in 2007, $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 September 30, 2007March 31, 2008 we have received $1.6 million from Williams for this indemnification.the Tahiti-related indemnification since inception.
     Although in 2007 we recently acquired an additional 20% ownership interest in Discovery, Discovery-relatedTahiti-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 may borrow up to $75.0have a $200.0 million under Williams’ $1.5 billion revolving credit facility which iswith Citibank, N.A. as administrative agent available for

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borrowings and letters of credit. Our $75.0 million borrowing limit under Williams’Under certain conditions, the revolving credit facility is available for general partnership purposes, including acquisitions, but onlymay 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 extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At September 30, 2007, the entire $75.0 million was available for our use.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 September 30, 2007March 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 ExpendituresRequirements
     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.

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The following table provides summary information related to our, Wamsutter’s and Discovery’s expected capital expenditures for 20072008 and actual spending through September 30, 2007 (millions)March 31, 2008 (in millions):
                                                
 Maintenance Expansion Total Maintenance Expansion Total
 Through Through Through   Through   Through   Through
Company Total Year Estimate Sept. 30, 2007 Total Year Estimate Sept. 30, 2007 Total Year Estimate Sept. 30, 2007 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 $6.9 $4.2 $6.5 $3.0 $13.4 $7.2  3.2 .6 13.9 1.0 17.1 1.6 
Four Corners 21.5 17.6 18.9 8.1 40.4 25.7 
Discovery — 100% 2.7 2.5 33.8 32.0 36.5 34.5 
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 
     For 2007, we estimate approximately $3.8 million of Conway’s maintenance capital expenditures will be reimbursed by Williams subject to the omnibus agreement.     We expect to fund the remainder of these expenditures through cash flows from operations. These expenditures relate primarily to cavern workoversFour Corners’ and wellhead modifications necessary to comply with KDHE regulations.
     ExpansionConway’s maintenance and expansion capital expenditures for the Conway assets are being funded from its own internally generated cash flows from operations.
     We expect Four Corners will continue to fund its maintenance capital expenditures through itswith cash flows from operations. For 2007, these2008, Four Corners’ estimate of maintenance capital expenditures include approximately $13.0$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. The $8.5 million balance relates to various smaller projects.
     We expect Four Corners will fund itsCorners’ 2008 expansion capital expenditures through its cash flows from operations. For 2007, these expenditures include estimates of approximately $5.0 million for certain well connections that we believe will increase throughput volumes in late 2007 and early 2008. The $13.9 million balance relatesrelate primarily to plant and gathering system expansion projects.
     We estimate approximately $0.2 million and $1.0 million of Discovery’s 2007 maintenance and Conway’s 2008 expansion capital expenditures respectively, may be reimbursed by Williams subjectrelate 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 omnibus agreement.Wamsutter system which serve to offset the historical decline in throughput volumes. We expect DiscoveryWamsutter will fund the remainder of its maintenance capital expenditures through its cash flows from operations. These maintenance
     Wamsutter funds its expansion capital expenditures relate to numerous small projects.
     For 2007, we estimatethrough 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 for 100%in excess of Discovery will$2.5 million at the time of approval and well connections that increase gathered volumes beyond current levels be approximately $33.8 million, offunded by contributions from its Class B membership, which we do not own. However, our 60% share is $20.3 million. Of the 100% amount, approximately $31.0 million is for the ongoing constructionownership of the Tahiti pipeline lateralClass A membership interest requires us to provide capital contributions related to expansion project. Discovery is fundingprojects with expected total expenditures less than $2.5 million at the originally approved expenditures with amounts previously escrowed for this project. We currently anticipate that the project will exceed the original estimate by approximately $3.5 million and that this amount will be funded with cash on hand or contributions from Discovery’s members, including us.time of approval.
     Discovery will fund its other2008 maintenance and expansion capital expenditures either by cash calls to its members which requires the unanimous consent of the members except in limited circumstances, or from internally generated funds.

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Carbonate Trend Overburden Restoration
     In compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline to assess the impact of Hurricane Ivan in 2004 and Hurricane Katrina in 2005. As a result of this survey, we determined that it was necessary to undertake certain restoration activities to repair the partial erosion of the pipeline overburden. We completed these restoration activities during the third quarter of 2007. The surveys and repairs were funded withits cash flows from operations in advance of our receiving a $2.0 million advance insurance payment in July 2007. The $0.6 million of repair costs have been offset against the $2.0 million advance payment. We anticipate we may be able to offset the remaining costs against the $1.4 million remainder of the advance payment. The completeness of these repairs is subject to regulatory approval by the U.S. Minerals Management Service, but they are under no obligation to provide us with notice of their approval. We consider the repair work to be complete.operations.
     Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our insurance carrier and subject to an overall limitation of $14.0 million for all indemnified environmental and related expenditures generally for a period of three years that ends in August 2008.
Debt Service — Long-Term Debt
     We have $150.0 million senior unsecured notes outstanding that bear interest at 7.5% per annum payable semi-annually in arrears on June 15 and December 15 of each year. The senior notes mature on June 15, 2011.
     Additionally, we have $600.0 million of 7.25% senior unsecured notes outstanding. The maturity date of the notes is February 1, 2017. Interest is payable semi-annually in arrears on February 1 and August 1 of each year, beginning on August 1, 2007.
Cash Distributions to Unitholders
     We have paid quarterly distributions to ourcommon and subordinated unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recently declaredrecent quarterly distribution of $24.3$37.9 million will be paid on November 14, 2007May 15, 2008 to the general partner interest and common and subordinated unitholders of record at the close of business on NovemberMay 7, 2007.2008. This distribution includes an additional incentive distribution to our general partner of approximately $2.2$5.5 million.
     Our general partner called a special meeting of common unitholders on May 21, 2007 to vote upon a proposal to approve (a) a change in the terms of our Class B units to provide that each Class B unit is convertible into one of our common units and (b) the issuance of additional common units upon such conversion (the “Class B Conversion and Issuance Proposal”). On May 21, 2007, at this meeting, by a majority vote of common units eligible to vote, the Class B units were converted into common units on a one-for-one basis.
Results of Operations — Cash Flows
Williams Partners L.P.
         
  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)
         
  Nine months ended
  September 30,
  2007 2006
  (Thousands)
         
Net cash provided by operating activities $129,065  $116,521 
         
Net cash used by investing activities $(101,369) $(168,527)
         
Net cash provided (used) by financing activities $(69,148) $83,298 
     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 $12.5$13.0 million increase in net cash provided by operating activities forin the first nine monthsquarter of 20072008 as compared to the first nine monthsquarter of 20062007 is due primarily to:
$51.3to $10.8 million increase in working capital excluding accrued interest. Cash provided by working capital increased due primarily to $25.5 million in favorable accounts receivable activity, which includes the following items in 2006:
a $16.1 million increase, in 2006, in affiliate receivables as a result of our transition from Williams’ cash management program to a stand-alone cash management program; and
an increase of $6.8 million from accounts receivable due from an affiliate for reimbursable compression projects.
Additionally, changes in our accounts payable and product imbalance activity between periods accounted for another $19.0 million in cash provided by working capital.
$2.9 million higher distributions related to the equity earnings of Discovery.
     Partially, offsetting these increases were $33.2 million in cash interest payments in June and August for the interest on our $750.0 million senior unsecured notes issued in 2006 to finance our acquisition of Four Corners and $9.3 million lower operating income, excludingas adjusted for non-cash items.expenses.
     Net cash used by investing activities in 2006 includes the purchasefirst quarter of a 25.1% interest in Four Corners on June 20, 2006. Net cash used by investing activities in2008 and 2007 includes the closingis primarily comprised of an additional 20% ownership interest in Discovery on June 28, 2007. Since Four Corners and Discovery were affiliates of Williams, the transactions were between entities under common control, and have been accounted for at historical cost. Therefore the amount reflected as cash used by investing activities for these purchases represents the historical cost to Williams. Additionally, net cash used by investing activities includes maintenance and expansion capital expenditures primarily used for well connects in our Four Corners business and the installation of cavern liners and KDHE-related cavern compliance with the installation of wellhead control equipment and well meters in our NGL Services segment.
     Net cash provided by financing activities in 2006 included various transactions related to the financingconnection of our purchasenew wells. Severe winter weather during the first quarter of 2008 reduced the 25.1% interest in Four Corners. Net cash used by financing activities for both years also includes our quarterly distributionsability to unitholders.
Discovery — 100 %
         
  Nine months ended
  September 30,
  2007 2006
  (Thousands)
         
Net cash provided by operating activities $39,557  $38,934 
         
Net cash used by investing activities  (7,444)  (9,486)
         
Net cash used by financing activities  (41,252)  (23,609)
     Net cash provided by operating activities increased $0.6 million in 2007 as compared to 2006 due primarily to a $1.4 million increase in operating income, adjusted for non-cash expenses, partially offset by a $0.8 million decrease in cash from changes in working capital.
     Net cash used by investing activities decreased in 2007 related primarily to decreased spending on the Tahiti pipeline lateral expansion project, which was not entirely funded from amounts previously escrowed in 2005 and included on the balance sheet as restricted cash.connect new wells.
     Net cash used by financing activities increased $17.6in 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 $12.6 million higherincreased distributions paid to membersmembers.
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 of $5.0 million lower capital contributions from members to finance capital projects.earnings when the underlying hedged NGLs are sold.

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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
     Certain of our and Discovery’s processing contractsWe are exposed to the impact of price fluctuations in the commodity markets, including the correlation betweenmarket price of natural gas liquids and NGL prices. In addition,natural gas, as well as other market factors, such as market volatility and commodity price fluctuations in commodity markets could impact the demand for our and Discovery’s services in the future. Our Carbonate Trend pipeline and our fractionation and storage operations are not directly affected by changing commodity prices except for product imbalances, whichcorrelations. 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 impactrisks associated with these market fluctuations using various derivative contracts. The fair value of price fluctuationderivative contracts is subject to changes in NGL markets. Price fluctuationsenergy-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 marketsprices, 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 also impactaffect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the demandindustry 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 storage and fractionation services in the future. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase ofnontrading purposes that hedge a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. This physical contract is intended to mitigate the fuelcommodity price risk under oneexposure from natural gas liquid sales and natural gas purchases. Certain of our fractionationderivative contracts which contains a cap on the per-unit fee that we can charge, at times limiting our ability to pass through the full amount of increases in variable expenses to that customer. This physical contract is a derivative; however, we elected to account for this contract under thehave been designated as normal purchases exemption to the fair value accounting that would otherwise apply. We also have physical contracts for the purchase of ethane and the sale of propane related to our operating supply management activities at Conway. These physical contracts are derivatives. However, we elected to account for these contracts under the normal purchases exemption as well.
Derivatives
     In May 2007, we hedged 8.8 million gallons of May through December 2007 forecasted NGLor sales using financial swap contracts with a range of fixed prices of $1.15 to $1.62 per gallon depending on the specific product. We receive the underlying NGL gallons as compensation for processing services provided at Four Corners. We have designated these derivatives as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.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 long-term senior unsecured notes have fixed interest rates. Any borrowings under our credit agreements would be at a variable interest rate risk exposure is related primarily to our debt portfolio and would expose ushas not materially changed during the first three months of 2008. See Note 6 of Notes to the risk of increasing interest rates. As of September 30, 2007, we did not have borrowings under our credit agreements.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 15(d)15d — (e) of the Securities Exchange Act) (“Disclosure Controls”)(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 officerChief Executive Officer and chief financial officerChief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
     Our management, including our general partner’s chief executive officerChief Executive Officer and chief financial officer,Chief Financial Officer, does not expect that our Disclosure Controls or our internal controls over financial reporting (“Internal Controls”)(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

36


detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and 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.
Third-Quarter 2007 Changes in Internal Control Over Financial Reporting
     There have been no changes during the thirdfirst quarter of 20072008 that have materially affected, or are reasonably likely to materially affect, our Internal Controlsinternal controls over financial reporting.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
     The information required for this item is provided in Note 8,9, 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,I., Item 1A. Risk Factors in our Annual Reportannual report on Form 10-K for the year ended December 31, 20062007, includes certain risk factors that could materially affect our business, financial condition or future results. Those risk factors have not materially changed.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 3.1Amended 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 31.1Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+Exhibit 31.2Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+Exhibit 32Section 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
NumberDescription
+Exhibit 3.1Amended 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.

3841


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) 
November 1, 2007

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EXHIBIT INDEX
Exhibit
NumberDescription
+Exhibit 31.1Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+Exhibit 31.2Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+Exhibit 32Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
+Filed herewith.